BAKER HUGHES a GE 10K 2005 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1–9397

Baker Hughes Incorporated

(Exact name of registrant as specified in its charter)


Delaware		76–0207995
(State or other jurisdiction		(I.R.S. Employer Identification No.)
of incorporation or organization)

3900 Essex Lane, Suite 1200, Houston, Texas		77027–5177
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:(713) 439–8600

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock, $1 Par Value per Share		New York Stock Exchange SWX Swiss Exchange

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YESþ NOo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. YESo NOþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YESþ NOo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form 10–K.þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non–accelerated filer.


Large accelerated filerþ		Accelerated filero		Non–accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). YESo NOþ

The aggregate market value of the voting and non–voting common stock held by non–affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing price on July 1, 2005 reported by the New York Stock Exchange) was approximately $17,495,000,000.

As of February 24, 2006, the registrant has outstanding 342,267,907 shares of common stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s 2005 Proxy Statement for the Annual Meeting of Stockholders to be held April 27, 2006 are incorporated by reference into Part III of this Form 10–K.

Baker Hughes Incorporated

INDEX


		Page
Part I

Item 1.	Business		2
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		19
Item 2.	Properties		19
Item 3.	Legal Proceedings		20
Item 4.	Submission of Matters to a Vote of Security Holders		21

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		21
Item 6.	Selected Financial Data		23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		42
Item 8.	Financial Statements and Supplementary Data		45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		79
Item 9A.	Controls and Procedures		79
Item 9B.	Other Information		79

Part III

Item 10.	Directors and Executive Officers of the Registrant		79
Item 11.	Executive Compensation		79
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		80
Item 13.	Certain Relationships and Related Transactions		82
Item 14.	Principal Accounting Fees and Services		82

Part IV

Item 15.	Exhibits and Financial Statement Schedules		83
Retirement and Consulting Agreement
Form of Baker Hughes Incorporated Restricted Stock Award
Form of Baker Hughes Incorporated Stock Option Award Agreement
Form of Baker Hughes Incorporated Performance Unit Award Agreement
Performance Goals for Performance Unit Award
Compensation Table for Named Executive Officers and Directors
Subsidiaries of Registrant
Consent of Deloitte & Touche LLP
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Statement of CEO and CFO pursuant to Rule 13a-14b

PART I

ITEM 1. BUSINESS

Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our” or “us”) is a Delaware corporation engaged in the oilfield services industry. Baker Hughes is a major supplier of wellbore-related products and technology services and systems to the worldwide oil and natural gas industry, including products and services for drilling, formation evaluation, completion and production of oil and natural gas wells. We conduct our operations through subsidiaries, affiliates, ventures and alliances.

Baker Hughes was formed in April 1987 in connection with the combination of Baker International Corporation and Hughes Tool Company. We acquired Western Atlas Inc. in a merger completed on August 10, 1998.

As used herein, “Baker Hughes,” “Company,” “we,” “our” and “us” may refer to Baker Hughes Incorporated or its subsidiaries. The use of these terms is not intended to connote any particular corporate status or relationships.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our Internet website at www.bakerhughes.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”).

We have adopted a Business Code of Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also required our principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct and Code of Ethical Conduct Certifications are available on the Investor Relations section of our website at www.bakerhughes.com. We intend to promptly disclose on our website information about any waiver of these codes for our executive officers and directors. Our Corporate Governance Guidelines and the charters of our Audit/Ethics Committee, Compensation Committee, Executive Committee, Finance Committee and Governance Committee are also available on the Investor Relations section of our website at www.bakerhughes.com. In addition, a copy of our Business Code of Conduct, Code of Ethical Conduct Certification, Corporate Governance Guidelines and the charters of the Committees referenced above are available in print at no cost to any stockholder who requests them by writing or telephoning us at the following address or telephone number:

Baker Hughes Incorporated
3900 Essex Lane, Suite 1200
Houston, TX 77027
Attention: Investor Relations
Telephone: (713) 439-8039

Information contained on or connected to our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing we make with the SEC.

We have organized our seven product-line focused divisions into two separate segments: Drilling and Evaluation and Completion and Production. The segments align product lines based on the types of products and services provided to our customers. We also own a 30% equity interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”). Accordingly, we report our results under three segments — Drilling and Evaluation, Completion and Production and WesternGeco:

	•		The Drilling and Evaluation segment consists of Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (conventional and rotary directional drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services). The Drilling and Evaluation segment provides products and services used to drill oil and natural gas wells.

	•		The Completion and Production segment consists of Baker Oil Tools (completion, workover and fishing equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electric submersible pumps and progressing cavity pumps). The Completion and Production segment also includes our Production Optimization business unit (permanent downhole monitoring). The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

	•		The WesternGeco segment consists of our equity interest in WesternGeco that provides reservoir imaging, monitoring and development services.

We have aggregated our divisions into these segments because they have similar economic characteristics and because their long-term financial performance is affected by similar economic conditions. They also operate in the same markets, which include all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

For additional industry segment information for the three years ended December 31, 2005, see Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.

DRILLING AND EVALUATION SEGMENT

Baker Hughes Drilling Fluids

Baker Hughes Drilling Fluids is a major provider of drilling fluids (also called “mud”), completion fluids (also called “brines”) and fluids environmental services. Drilling fluids are an important component of the drilling process and are pumped from the surface through the drill string, exiting nozzles in the drill bit and traveling back up the wellbore where the fluids are recycled. This process cleans the bottom of the well by transporting the cuttings to the surface while also cooling and lubricating the bit and drill string. Drilling fluids typically contain barite or bentonite to give them weight, which enables the fluids to hold the wellbore open and stabilize it. Additionally, the fluids control downhole pressures and seal porous sections of the wellbore. To ensure maximum efficiency and wellbore stability, drilling fluids are often customized by the wellsite engineer. For drilling through the reservoir itself, Baker Hughes Drilling Fluids’ drill-in or completion fluids possess properties that minimize formation damage. The fluids environmental services of Baker Hughes Drilling Fluids also provide equipment and services to separate the drill cuttings from the drilling fluids and re-inject the processed cuttings into a specially prepared well, or to transport and dispose of the cuttings by other means.

Although technology is very important in the selection of drilling fluids for many drilling programs, cost efficiency tends to drive customer purchasing decisions. Specific opportunities for competitive differentiation include:

	•		improving drilling efficiency,

	•		minimizing formation damage, and

	•		handling and disposing of drilling fluids and cuttings in an environmentally safe manner.

Baker Hughes Drilling Fluids’ primary competitors include M-I SWACO, Halliburton Company (“Halliburton”), Newpark Resources, Inc. and various other competitors.

Key business drivers for Baker Hughes Drilling Fluids include the number of drilling rigs operating (especially the number of drilling programs targeting deep formations), total footage drilled, environmental regulations, as well as the current and expected future price of both oil and natural gas.

Hughes Christensen

Hughes Christensen is a leading manufacturer and supplier of drill bits, primarily Tricone^® roller cone bits and fixed-cutter polycrystalline diamond compact (“PDC”) bits, to the worldwide oil and natural gas industry. The primary objective of a drill bit is to drill a high quality wellbore as efficiently as possible.

Tricone^® Bits.Tricone^® drill bits employ either hardened steel teeth or tungsten carbide insert cutting structures mounted on three rotating cones. These bits work by crushing and shearing the formation rock as they are turned. Tricone^® drill bits have a wide application range.

PDC Bits.PDC (also known as “Diamond”) bits use fixed position cutters that shear the formation rock with a milling action as they are turned. In many softer and less variable applications, PDC bits offer higher penetration rates and a longer life than Tricone^® bits. Advances in PDC technology have expanded the application of PDC bits into harder, more abrasive formations. A rental market has developed for PDC bits in the Western Hemisphere as improvements in bit life and bit repairs allow a bit to be used to drill multiple wells.

The main driver of customer purchasing decisions in drill bits is the value added, usually measured in terms of savings in total operating costs per distance drilled. Specific opportunities for competitive differentiation include:

	•		improving the rate of penetration,

	•		extending bit life, and

	•		selecting the optimal bit for each section to be drilled.

Hughes Christensen’s primary competitors in the oil and natural gas drill bit market are Smith International, Inc. (“Smith”), Grant Prideco, Inc., Halliburton and various other competitors.

Key business drivers for Hughes Christensen include the number of drilling rigs operating, total footage drilled, drilling rig rental costs, as well as the current and expected future price of both oil and natural gas.

INTEQ

INTEQ is a leading supplier of drilling and evaluation services, which include directional drilling, measurement-while-drilling (“MWD”) and logging–while–drilling (“LWD”) services.

Directional Drilling. Directional drilling services are used to guide a drill string along a predetermined path to drill a wellbore to optimally recover hydrocarbons from the reservoir. These services are used to accurately drill vertical wells, deviated or directional wells (which deviate from vertical by a planned angle and direction), horizontal wells (which are sections of wells drilled perpendicular or nearly perpendicular to vertical) and extended reach wells.

INTEQ is a leading supplier of both conventional and rotary based directional drilling systems. Conventional directional drilling systems employ a downhole motor that turns the drill bit independently of drill string rotation from the surface. Placed just above the bit, a steerable motor assembly has a bend in its housing that is oriented to steer the well’s course. During the “rotary” mode, the entire drill string is rotated from the surface, negating the effect of this bend and causing the bit to drill on a straight course. During the “sliding” mode, drill string rotation is stopped and a “mud” motor (which converts hydraulic energy from the drilling fluids being pumped through the drill string into rotational energy at the bit) allows the bit to drill in the planned direction by orienting its angled housing, gradually guiding the wellbore through an arc.

INTEQ was a pioneer and is a leader in the development and use of automated rotary steerable technology. In rotary steerable environments, the entire drill string is turned from the surface to supply energy to the bit. Unlike conventional systems, INTEQ’s AutoTrak^® rotary steerable system changes the trajectory of the well using three pads that push against the wellbore from a non-rotating sleeve and is controlled by a downhole guidance system.

INTEQ’s AutoTrak^® Xtreme^® system combines conventional mud motor technology with rotary steerable technology to provide directional control and improved rate of penetration.

Measurement-While-Drilling.Directional drilling systems need real-time measurements of the location and orientation of the bottom hole assembly to operate effectively. INTEQ’s MWD systems are downhole tools that provide this directional information, which is necessary to adjust the drilling process and guide the wellbore to a specific target. The AutoTrak^® rotary steerable system has these MWD systems built in, allowing the tool to automatically alter its course based on a planned trajectory.

Logging-While-Drilling.LWD is a variation of MWD in which the LWD tool gathers information on the petrophysical properties of the formation through which the wellbore is being drilled. Many LWD measurements are the same as those taken via wireline; however, taking them in real-time often allows for greater accuracy, as measurements occur before any damage has been sustained by the reservoir as a result of the drilling process. Real-time measurements also enable “geo-steering” where geological markers identified by LWD tools are used to guide the bit and assure placement of the wellbore in the optimal location.

In both MWD and LWD systems, surface communication with the tool is achieved through mud-pulse telemetry, which uses pulse signals (pressure changes in the drilling fluid traveling through the drill string) to communicate the operating conditions and location of the bottom hole assembly to the surface. The information transmitted is used to maximize the efficiency of the drilling process, update and refine the reservoir model and steer the well into the optimal location in the reservoir.

As part of INTEQ’s mud logging services, engineers monitor the interaction between the drilling fluid and the formation and perform laboratory analysis of drilling fluids and examinations of the drill cuttings to detect the presence of hydrocarbons and identify the different geological layers penetrated by the drill bit.

The main drivers of customer purchasing decisions in these areas are the value added by technology and the reliability and durability of the tools used in these operations. Specific opportunities for competitive differentiation include:

	•		the sophistication and accuracy of measurements,

	•		the efficiency of the drilling process (measured in cost per foot drilled),

	•		the reliability of equipment,

	•		the optimal placement of the wellbore in the reservoir, and

	•		the quality of the wellbore.

INTEQ’s primary competitors in drilling and evaluation services are Halliburton, Schlumberger, Weatherford International Ltd. (“Weatherford”) and various other competitors.

Key business drivers for INTEQ include the number of drilling rigs operating, the total footage drilled, the mix of conventional and rotary steerable systems used, as well as the current and expected future price of both oil and natural gas.

Baker Atlas

Baker Atlas is a leading provider of formation evaluation and wireline completion and production services for oil and natural gas wells.

Formation Evaluation.Formation evaluation involves measuring and analyzing specific physical properties of the rock (petrophysical properties) in the immediate vicinity of a wellbore to determine an oil or natural gas reservoir’s boundaries, volume of hydrocarbons and ability to produce fluids to the surface. Electronic sensor instrumentation is run through the wellbore to measure porosity and density (how much open space there is in the rock), permeability (how well connected the spaces in the rock are) and resistivity (whether there is oil, natural gas or water in the spaces). Imaging tools are run through the wellbore to record a picture of the formation along the well’s length similar to a core sample. Acoustic logs measure rock properties and help correlate wireline data with previous seismic surveys. Magnetic resonance measurements characterize the volume and type of fluids in the formation as well as providing a direct measure of permeability. At the surface, measurements are recorded digitally and can be displayed on a continuous graph, or “well log,” which shows how each parameter varies along the length of the wellbore. Formation evaluation tools can also be used to record formation pressures and take samples of formation fluids to be further evaluated on the surface.

Formation evaluation instrumentation can be run in the well in several ways and at different times over the life of the well. The two most common methods of data collection are wireline logging (performed by Baker Atlas) and LWD (performed by INTEQ). Wireline logging is conducted by pulling or pushing instruments through the wellbore after it is drilled, while LWD instruments are attached to the drill string and take measurements while the well is being drilled. Wireline logging measurements can be made before the well’s protective steel casing is set (open hole logging) or after casing has been set (cased hole logging). Baker Atlas also offers geophysical data interpretation services which help the operator interpret the petrophysical properties measured by the logging instruments and make inferences about the formation, presence and quantity of hydrocarbons present. This information is used to determine the next steps in drilling and completing the well.

Wireline Completion and Production Services.Wireline completion and production services include using wireline instruments to evaluate well integrity, perform mechanical intervention and perform cement evaluations. Wireline instruments can also be run in producing wells to perform production logging. Baker Atlas (and Baker Oil Tools) also provide perforating services, which involve puncturing a well’s steel casing and cement sheath with explosive charges. This creates a fracture in the formation and provides a path for hydrocarbons in the formation to enter the wellbore and be produced.

Baker Atlas’ services allow oil and natural gas companies to define, manage and reduce their exploration and production risk. As such, the main driver of customer purchasing decisions is the value added by formation evaluation and wireline completion and production services. Specific opportunities for competitive differentiation include:

	•		the efficiency of data acquisition,

	•		the sophistication and accuracy of measurements,

	•		the ability to interpret the information gathered to quantify the hydrocarbons producible from the formation, and

	•		the ability to differentiate services that can run exclusively or more efficiently on wireline from services that can run on either wireline or drill pipe.

Baker Atlas’ primary formation evaluation and wireline completion and perforating competitors are Schlumberger, Weatherford, Halliburton and various other competitors.

Key business drivers for Baker Atlas include the number of drilling and workover rigs operating, as well as the current and expected future price of both oil and natural gas.

COMPLETION AND PRODUCTION SEGMENT

Baker Oil Tools

Baker Oil Tools is a world leader in well completion and wellbore intervention solutions.

Well Completion.The economic success of a well largely depends on how the well is completed. A successful completion ensures and optimizes the efficient and safe production of oil and natural gas to the surface. Baker Oil Tools’ completion systems are matched to the formation and reservoir for optimum production and can employ a variety of products and services including liner hangers, packers, flow control equipment, subsurface safety valves, sand control equipment and other advanced completion technologies.

Liner hangers suspend a section of steel casing (also called a liner) inside the bottom of the previous section of casing. The liner hanger’s expandable slips grip the inside of the casing and support the weight of the liner below.

Packers seal the annular space between the steel production tubing and the casing. These tools control the flow of fluids in the well and protect the casing above and below from reservoir pressures and corrosive formation fluids.

Flow control equipment controls and adjusts the flow of downhole fluids. A common flow control device is a sliding sleeve, which can be opened or closed to allow or limit production from a particular portion of a reservoir. Flow control can be accomplished from the surface via wireline or downhole via hydraulic or electric motor-based automated systems.

Subsurface safety valves shut off all flow of fluids to the surface in the event of an emergency, thus saving the well and preventing pollution of the environment. These valves are required in substantially all offshore wells.

Sand control equipment includes gravel pack tools, sand screens and fracturing fluids. Sand control systems and pumping services are used in loosely consolidated formations to prevent the production of formation sand with the hydrocarbons.

Advanced completion technologies include multilateral systems, intelligent well systems and expandable metal technologies. Multilateral completion systems enable two or more zones to be produced from a single well, using multiple horizontal branches. Intelligent Completions^® use real-time, remotely operated downhole systems to control the flow of hydrocarbons from one or more zones. Expandable metal technology involves the permanent downhole expansion of a variety of tubular products used in drilling, completion and well remediation applications.

Wellbore Intervention.Wellbore intervention products and services are designed to protect producing assets. Intervention operations troubleshoot drilling problems and improve, maintain or restore economical production from already-producing wells. In this area, Baker Oil Tools offerings range from service tools and inflatable products to conventional and through-tubing fishing systems, casing exits, wellbore cleaning and temporary abandonment.

Service tools function as surface-activated, downhole sealing and anchoring devices to isolate a portion of the wellbore during repair or stimulation operations. Service tool applications range from treating and cleaning to testing components from the wellhead to the perforations. Service tools also refer to tools and systems that are used for temporary or permanent well abandonment.

Inflatable packers expand to set in pipe that is much larger than the outside diameter of the packer itself, so it can run through a restriction in the well and then set in the larger diameter below. Inflatable packers also can be set in “open hole” whereas conventional tools only can be set inside casing. Through-tubing inflatables enable remedial operations in producing wells. Significant cost savings result from lower rig requirements and the ability to intervene in the well without having to remove the completion.

Fishing tools and services are used to locate, dislodge and retrieve damaged or stuck pipe, tools or other objects from inside the wellbore, often thousands of feet below the surface.

Wellbore cleaning systems remove post-drilling debris to help ensure trouble-free well testing and completion and optimum production for the life of the well.

Casing exit systems are used to “sidetrack” new wells from existing ones, to provide a cost-effective method of tapping previously unreachable reserves.

The main drivers of customer purchasing decisions in well completion and wellbore intervention are superior wellsite service execution and value-adding technologies that improve production rates, protect the reservoir from damage and reduce cost. Specific opportunities for competitive differentiation include:

	•		engineering and manufacturing superior-quality products and providing solutions with a proven ability to reduce well construction costs,

	•		enhancing production and ultimate recovery,

	•		minimizing risks, and

	•		providing reliable performance over the life of the well, particularly in harsh environments and for critical wells.

Baker Oil Tools’ primary competitors in well completion are Halliburton, Schlumberger, Weatherford and various other competitors. Its primary competitors in wellbore intervention are Halliburton, Schlumberger, Weatherford, Smith and various other competitors.

Key business drivers for Baker Oil Tools include the number of drilling and workover rigs operating, the relative complexity of the wells drilled and completed, as well as the current and expected future price of both oil and natural gas.

Baker Petrolite

Baker Petrolite is a leading provider of specialty chemicals to the oil and gas industry. The division also supplies specialty chemicals to a number of industries including refining, pipeline transportation, petrochemical, agricultural and iron and steel manufacturing and provides polymer-based products to a broad range of industrial and consumer markets. Through its Pipeline Management Group (“PMG”), Baker Petrolite also offers a variety of products and services for the pipeline transportation industry.

Oilfield Chemicals.Baker Petrolite provides oilfield chemical programs for drilling, well stimulation, production, pipeline transportation and maintenance programs. Its products provide measurable increases in productivity, decreases in operating and maintenance cost and solutions to environmental problems. Examples of specialty oilfield chemical programs include chemicals which inhibit hydrate-, paraffin-, scale- and corrosion-formation and emulsion breakers.

Hydrate inhibitors — Natural gas hydrates are solid ice-like crystals that form in production flowlines and tubing and cause shutdowns and the need for system maintenance. Subsea wells and flowlines, particularly in deepwater environments, are especially susceptible to hydrates.

Paraffin inhibitors — The liquid hydrocarbons produced from many oil and natural gas reservoirs become unstable soon after leaving the formation. Changing conditions, including decreases in temperature and pressure, can cause certain hydrocarbons in the produced fluids to crystallize and deposit on the walls of the well’s tubing, flow lines and surface equipment. These deposits are commonly referred to as paraffin. Baker Petrolite offers solvents that remove the deposits, as well as inhibitors that prevent new deposits from forming.

Scale inhibitors — Unlike paraffin deposits that originate from organic material in the produced hydrocarbons, scale deposits come from mineral-based contaminants in water that are produced from the formation as the water undergoes changes in temperature or pressure. Similar to paraffin, scale deposits can clog the production system. Treatments prevent and remove deposits in production systems.

Corrosion inhibitors — Another problem caused by water mixed with downhole hydrocarbons is corrosion of the well’s tubulars and other production equipment. Corrosion can also be caused by dissolved hydrogen sulfide (“H₂S”) gas, which reacts with the iron

in tubulars, valves and other equipment, potentially causing failures and leaks. Additionally, the reaction creates iron sulfide, which can impair treating systems and cause blockages. Baker Petrolite offers a variety of corrosion inhibitors and H₂S scavengers.

Emulsion breakers — Water and oil typically do not mix, but water present in the reservoir and co-produced with oil can often become emulsified, or mixed, causing problems for oil and natural gas producers. Baker Petrolite offers emulsion breakers that allow the water component of the emulsion to be separated from the oil.

Refining, Industrial and Other Specialty Chemicals.For the refining industry, Baker Petrolite offers various process and water treatment programs, as well as finished fuel additives. Examples include programs to remove salt from crude oil and to control corrosion in processing equipment and environmentally friendly cleaners that decontaminate refinery equipment and petrochemical vessels at a lower cost than other methods. Baker Petrolite also provides chemical technology solutions to other industrial markets throughout the world, including petrochemicals, fuel additives, plastics, imaging, adhesives, steel and crop protection.

Pipeline Management.Baker Petrolite’s Pipeline Management Group (“PMG”) offers a variety of products and services for the pipeline transportation industry. To improve efficiency, Baker Petrolite offers custom turnkey cleaning programs that combine chemical treatments with brush and scraper tools that are pumped through the pipeline. Efficiency can also be improved by adding polymer-based drag reduction agents to reduce the slowing effects of friction between the pipeline walls and the fluids within, thus increasing throughput and pipeline capacity. Additional services allow pipelines to operate more safely. These include inspection and internal corrosion assessment technologies, which physically confirm the structural integrity of the pipeline. In addition, PMG’s flow-modeling capabilities can identify high-risk segments of a pipeline to ensure proper mitigation programs are in place.

The main driver of customer purchasing decisions in specialty chemicals is superior application of technology and service delivery. Specific opportunities for competitive differentiation include:

	•		higher levels of production or throughput,

	•		lower maintenance costs and frequency,

	•		lower treatment costs and treatment intervals, and

	•		successful resolution of environmental issues.

Baker Petrolite’s primary competitors are GE Water Technologies, Nalco Company, Champion Technologies, Smith and various other competitors.

Key business drivers for Baker Petrolite include oil and natural gas production levels, the number of producing wells, total liquids production, and the current and expected future price of both oil and natural gas.

Centrilift

Centrilift is a leading manufacturer and supplier of electrical submersible pump systems (“ESPs”) and progressing cavity pump systems (“PCPs”).

Electrical Submersible Pump Systems.ESPs lift high quantities of oil or oil and water from wells that do not flow under their own pressure. These “artificial lift” systems consist of a centrifugal pump and electric motor installed in the wellbore, armored electric cabling to provide power to the downhole motor and a variable speed controller at the surface. Centrilift designs, manufactures, markets and installs all the components of ESP systems and also offers modeling software to size ESPs and simulate operating performance. ESPs may be used in both onshore or offshore wells. The range of appropriate application of ESP systems is expanding as technology and reliability enhancements have improved ESP system performance in harsher environments and marginal reservoirs.

Progressing Cavity Pump Systems.PCPs are a form of artificial lift comprised of a downhole progressing cavity pump powered by either a downhole electric motor or a rod turned by a motor on the surface. PCP systems are preferred when the fluid to be lifted is viscous or when the volume is significantly less than could be economically lifted with an ESP system.

The main drivers of a customer purchasing decision in artificial lift include the depth of the well, the volume of the fluid, the physical and chemical properties of the fluid as well as the capital and operating cost of the system. Specific opportunities for competitive differentiation include:

	•		the ability to lift fluids of differing physical properties and chemical compositions,

	•		system reliability and run life,

	•		the ability of the system to optimize production,

	•		operating efficiency, and

	•		service delivery.

Centrilift’s primary competitors in the ESP market are Schlumberger, John Wood Group PLC (“ESP Inc.”) and various other competitors. In the PCP market the primary competitors are Weatherford, Robbins & Myers, Inc., Kudu Industries, Inc. and various other competitors.

Key business drivers for Centrilift include oil production levels, as well as the current and expected future price of oil, the volume of water produced in mature basins and gas dewatering in coal bed methane and other gas wells.

Production Optimization

The Production Optimization business unit is a leading provider of permanent monitoring systems and chemical automation systems.

Permanent Monitoring Systems.Permanent downhole gauges are used in oil and gas wells to measure temperature, pressure, flow and other parameters in order to monitor well production as well as to confirm the integrity of the completion and production equipment in the well. Production Optimization is a leading provider of electronic gauges including the engineering, application and field services necessary to complete an installation of a permanent monitoring system. In addition, they provide chemical injection line installation and services for treating wells for corrosion, paraffin, scale and other well performance problems. They also provide fiber optic based permanent downhole gauge technology for measuring pressure, temperature and distributed temperature. The benefits of fiber optic sensing include reliability, high temperature properties and the ability for distributed readings.

Chemical Automation Systems.Chemical automation systems remotely monitor chemical tank levels that are resident in producing field locations for well treatment or production stimulation as well as continuously monitor and control chemicals being injected in individual wells. By using these systems, a producer can insure proper chemical injection through real time monitoring and can also remotely modify the injection parameters to insure optimized production.

The main drivers of customer purchasing decisions for both permanent monitoring and chemical automation include application engineering expertise, ability to integrate a complete system, product reliability, functionality and local field support. Specific opportunities for competitive differentiation include:

	•		the ability to provide application engineering and economic return analysis,

	•		innovative products,

	•		gauge measurement accuracy,

	•		product life and performance, and

	•		installation and service capabilities.

Production Optimization’s primary competitors are Schlumberger, Halliburton and Weatherford.

Key business drivers for Production Optimization include the level of oil and gas prices, total daily oil and gas production and capital spending for critical wells (offshore, sub-sea, high production on-shore and remotely located on-shore).

WesternGeco

WesternGeco is a seismic venture in which we own 30% and Schlumberger owns 70%. WesternGeco provides comprehensive worldwide reservoir imaging, monitoring and development services. The venture provides these services through its extensive

number of seismic crews and data processing centers, as well as through its ownership of one of the world’s largest multiclient seismic libraries. Services range from 3D and time-lapse (4D) seismic surveys to multicomponent surveys for delineating prospects and reservoir management. WesternGeco is positioned to meet the full range of customer needs in land, marine and shallow-water transition-zone areas.

Seismic solutions include proprietary Q-Technology* for enhanced reservoir description, characterization and monitoring throughout the life of the field — from exploration through enhanced recovery.

WesternGeco’s Omega* Seismic Processing System encompasses one of the industry’s most advanced and comprehensive suites of algorithms and runs on multiplatform technology, ensuring timely turnaround for even the most complex processing projects.

WesternGeco’s major competitors are Compagnie Generale de Geophysique, Veritas DGC, Inc. and Petroleum Geo-Services ASA.

For additional information related to WesternGeco, see the “Related Party Transactions” section in Item 7 and Note 8 of the Notes to Consolidated Financial Statements in Item 8, both contained herein.

* Mark of WesternGeco

MARKETING, COMPETITION AND ECONOMIC CONDITIONS

We market our products and services on a product line basis primarily through our own sales organizations, although certain of our products and services are marketed through supply stores, independent distributors, agents, licensees or sales representatives. We ordinarily provide technical and advisory services to assist in our customers’ use of our products and services. Stock points and service centers for our products and services are located in areas of drilling and production activity throughout the world.

Our products and services are sold in highly competitive markets, and revenues and earnings can be affected by changes in competitive prices, fluctuations in the level of drilling, workover and completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and governmental regulations. We compete with the oil and natural gas industry’s largest diversified oilfield services providers, as well as many small companies. We believe that the principal competitive factors in our industries are product and service quality, availability and reliability, health, safety and environmental standards, technical proficiency and price.

Further information is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

INTERNATIONAL OPERATIONS

We operate in over 90 countries worldwide, and our operations are subject to the risks inherent in doing business in multiple countries with various laws and differing political environments. These risks include the risks identified in “Item 1A. Risk Factors.” Although it is impossible to predict the likelihood of such occurrences or their effect on us, division and corporate management routinely evaluate these risks and take appropriate actions to mitigate the risks where possible. However, there can be no assurance that an occurrence of any one or more of these events would not have a material adverse effect on our operations.

Further information is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

RESEARCH AND DEVELOPMENT; PATENTS

We are engaged in research and development activities directed primarily toward the improvement of existing products and services, the design of specialized products to meet specific customer needs and the development of new products, processes and services. For information regarding the amounts of research and development expense in each of the three years in the period ended December 31, 2005, see Note 17 of the Notes to Consolidated Financial Statements in Item 8 herein.

We have followed a policy of seeking patent and trademark protection both inside and outside the United States for products and methods that appear to have commercial significance. We believe our patents and trademarks to be adequate for the conduct of our business, and aggressively pursue protection of our patents against patent infringement worldwide. Although, patent and trademark

protection is important to our business and future prospects, we consider the reliability and quality of our products and the technical skills of our personnel to be more important. No single patent or trademark is considered to be critical to our business.

RAW MATERIALS

We purchase various raw materials and component parts for use in manufacturing our products. The principal materials we purchase are steel alloys (including chromium and nickel), titanium, beryllium, copper, tungsten carbide, synthetic and natural diamonds, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. These materials are generally available from multiple sources and could be subject to rising costs. We have not experienced significant shortages of these materials and normally do not carry inventories of such materials in excess of those reasonably required to meet our production schedules. We do not expect significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

OTHER DEVELOPMENTS

In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“SPD”), a product line group within the Baker Oil Tools division of the Completion and Production segment. SPD distributes basic supplies, products and small tools to the drilling industry. In January 2006, we signed a non–binding letter of intent for the sale of SPD. The sale is expected to close in the first quarter of 2006. We have reflected SPD as a discontinued operation in the consolidated financial statements. SPD had revenues of $32.5 million for the year ended December 31, 2005. This transaction is subject to the negotiation and execution of a definitive sale agreement, as well as, various conditions, including satisfactory due diligence review of SPD’s business. There can be no assurance that the transaction will be consummated.

In December 2005, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million in cash, which is included in the Baker Oil Tools division of the Completion and Production segment. As a result of the acquisition and based on preliminary estimates of fair values, we recorded approximately $19.5 million of goodwill and intangible assets, which may be revised based on the final purchase price allocations. The purchase price was preliminarily allocated based on the fair values of the assets acquired and liabilities assumed in the acquisition. Under the terms of the Purchase Agreement, the former owners of Zertech are entitled to additional purchase price consideration of up to approximately $14.0 million based on the performance of the business during 2006, 2007 and 2008.

In October 2005, we finalized the purchase of the remaining 50% interest in QuantX Wellbore Instrumentation venture (“QuantX”), a venture engaged in permanent in–well monitoring, for $27.2 million, subject to final purchase price adjustments. QuantX is included in the Production Optimization business unit of the Completion and Production segment. Based on our carrying value of our existing investment in QuantX of $35.5 million and the additional consideration of $27.2 million, we recorded approximately $28.4 million of goodwill and $19.6 million of intangibles. We also assigned $5.1 million to in–process research and development that was written off at the date of acquisition. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed of QuantX. The fair values were determined using a discounted cash flow approach.

In January 2006, we acquired Nova Technology Corporation (“Nova”) for approximately $67.0 million in cash and assumed debt. Nova is a leading supplier of permanent monitoring, chemical injection systems, and multi–line services for deepwater and subsea oil and gas well applications and will be included in the Production Optimization business unit of the Completion and Production segment.

EMPLOYEES

On December 31, 2005, we had approximately 29,100 employees, as compared with approximately 26,900 employees on December 31, 2004. Approximately 2,590 of these employees are represented under collective bargaining agreements or similar–type labor arrangements, of which the majority are outside the U.S. Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole. We believe that our relations with our employees are good.

EXECUTIVE OFFICERS

The following table shows, as of February 28, 2006, the name of each of our executive officers, together with his age and all offices presently held.


Name	Age
Chad C. Deaton		53	Chairman of the Board and Chief Executive Officer of the Company since 2004. President and Chief Executive Officer of Hanover Compressor Company from 2002 to 2004. Senior Advisor to Schlumberger Oilfield Services from 1999 to 2001. Executive Vice President of Schlumberger from 1998 to 1999. Employed by the Company in 2004.

James R. Clark		55	President and Chief Operating Officer of the Company since February 2004. Vice President, Marketing and Technology of the Company from 2003 to 2004. Vice President of the Company and President of Baker Petrolite Corporation from 2001 to 2003. President and Chief Executive Officer of Consolidated Equipment Companies, Inc. from 2000 to 2001 and President of Sperry–Sun from 1996 to 1999. Employed by the Company in 2001.

G. Stephen Finley		55	Senior Vice President — Finance and Administration and Chief Financial Officer of the Company since 1999. Senior Vice President and Chief Administrative Officer of the Company from 1995 to 1999, Controller from 1987 to 1993 and Vice President from 1990 to 1995. Chief Financial Officer of Baker Hughes Oilfield Operations from 1993 to 1995. Employed by the Company in 1982. Mr. Finley has announced he will retire on March 31, 2006.

Alan R. Crain, Jr.		54	Vice President and General Counsel of the Company since October 2000. Executive Vice President, General Counsel and Secretary of Crown, Cork & Seal Company, Inc. from 1999 to 2000. Vice President and General Counsel from 1996 to 1999, and Assistant General Counsel from 1988 to 1996, of Union Texas Petroleum Holdings, Inc. Employed by the Company in 2000.

Greg Nakanishi		54	Vice President, Human Resources of the Company since November 2000. President of GN Resources from 1989 to 2000. Employed by the Company in 2000.

David H. Barr		56	Group President of Drilling and Evaluation since February 2005 and Vice President of the Company since 2000. President of Baker Atlas from 2000 to 2005. Vice President, Supply Chain Management, of Cooper Cameron from 1999 to 2000. Mr. Barr also held the following positions with the Company: Vice President, Business Process Development, from 1997 to 1998 and the following positions with Hughes Tool Company/Hughes Christensen: Vice President, Production and Technology, from 1994 to 1997; Vice President, Diamond Products, from 1993 to 1994; Vice President, Eastern Hemisphere Operations, from 1990 to 1993 and Vice President, North American Operations, from 1988 to 1990. Employed by the Company in 1972.

Douglas J. Wall		53	Group President of Completion and Production since February 2005 and Vice President of the Company since 1997. President of Baker Oil Tools from 2003 to 2005 and President of Hughes Christensen from 1997 to 2003. President and Chief Executive Officer of Western Rock Bit Company Limited, Hughes Christensen’s former distributor in Canada, from 1991 to 1997. General Manager of Century Valve Company from 1989 to 1991 and Vice President, Contracts and Marketing, of Adeco Drilling & Engineering from 1980 to 1989. Employed by the Company in 1997.

Christopher P. Beaver		48	Vice President of the Company and President of Baker Oil Tools since February 2005. Vice President of Finance for Baker Petrolite from 2002 to 2005; Director of Finance and Controller at INTEQ from 1999 to 2002; Controller at Hughes Christensen from 1994 to 1999. Various accounting and finance positions at Hughes Christensen in the Eastern Hemisphere from 1985 to 1994. Employed by the Company in 1985.

Paul S. Butero		49	Vice President of the Company and President of Hughes Christensen since 2005. Vice President, Marketing, of Hughes Christensen from 2001 to 2005 and as Region Manager for various Hughes


Name	Age
			Christensen areas (both in the United States and the Eastern Hemisphere) from 1989 to 2001. Employed by the Company in 1981.

Martin S. Craighead		46	Vice President of the Company since 2005 and President of INTEQ since August 2005. Served as President of Baker Atlas from February 2005 to August 2005. Vice President of Worldwide Operations for Baker Atlas from 2003 to 2005 and Vice President, Marketing and Business Development for Baker Atlas from 2001 to 2003; Region Manager for Baker Atlas in Latin America and Asia and Region Manager for E&P Solutions from 1995 to 2001. Research Engineer for BJ Services Company from 1982 to 1986. Employed by the Company in 1986.

William P. Faubel		50	Vice President of the Company since 2001 and President of Baker Atlas since 2006. Served as President of Centrilift from 2001 to 2006. Vice President, Marketing, of Hughes Christensen from 1994 to 2001 and as Region Manager for various Hughes Christensen areas (both domestic and international) from 1986 to 1994. Employed by the Company in 1977.

Alan J. Keifer		51	Vice President and Controller of the Company since July 1999. Western Hemisphere Controller of Baker Oil Tools from 1997 to 1999 and Director of Corporate Audit for the Company from 1990 to 1996. Employed by the Company in 1990.

Jay G. Martin		54	Vice President, Chief Compliance Officer and Senior Deputy General Counsel since July 2004. Shareholder at Winstead Sechrest & Minick P.C. from 2001 to July 2004. Partner, Phelps Dunbar from 2000 to 2001 and Partner, Andrews & Kurth from 1996 to 2000. Employed by the Company in 2004.

John A. O’Donnell		58	Vice President of the Company since 1998 and President of Baker Petrolite Corporation since May 2005. President of Baker Hughes Drilling Fluids from 2004 to 2005. Vice President, Business Process Development of the Company from 1998 to 2002; Vice President, Manufacturing, of Baker Oil Tools from 1990 to 1998 and Plant Manager of Hughes Tool Company from 1988 to 1990. Employed by the Company in 1975.

Richard L. Williams		50	Vice President of the Company and President of Baker Hughes Drilling Fluids since May 2005. Vice President, Eastern Hemisphere Operations, Baker Oil Tools from March 2005 to May 2005. Worldwide Operations Vice President, INTEQ from 2004 to 2005. Vice President Eastern Hemisphere, INTEQ from 2003 to 2004. Vice President Western Hemisphere, INTEQ from 2001 to 2003. Employed by the Company since 1975.

Charles S. Wolley		51	Vice President of the Company and President of Centrilift since January 2006. Vice President of Manufacturing and Technology, Hughes Christensen from 2004 to 2006. Senior Vice President of Supply Chain Operations, Dresser Flow Solutions 2003. President, Dresser Measurement and Control from 2002 to 2003 and Senior Vice President from 2001 to 2002. Chief Executive Officer Van Leeuwen Pipe and Tube Corp. from 1999 to 2001. Employed by the Company since 2004.

There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

We are committed to the health and safety of people, protection of the environment and compliance with laws, regulations and our policies. Our past and present operations include activities that are subject to domestic (including U.S. federal, state and local) and international regulations with regard to air and water quality and other environmental matters. We believe we are in substantial compliance with these regulations. Regulation in this area continues to evolve, and changes in standards of enforcement of existing regulations, as well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement or replace equipment or facilities or to change or discontinue present methods of operation.

We are involved in voluntary remediation projects at some of our present and former manufacturing facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency–issued consent decree or agreed order. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based

on internal evaluations and are not discounted. Such accruals are recorded when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.

During the year ended December 31, 2005, we spent approximately $32.1 million to comply with domestic and international standards regulating the discharge of materials into the environment or otherwise relating to the protection of the environment (collectively, “Environmental Regulations”). This cost includes the total spent on remediation projects at current or former sites, Superfund projects and environmental compliance activities, exclusive of capital. In 2006, we expect to spend approximately $34.2 million to comply with Environmental Regulations. Based upon current information, we believe that our compliance with Environmental Regulations will not have a material adverse effect upon our capital expenditures, earnings or competitive position because we have either established adequate reserves or our cost for that compliance is not expected to be material to our consolidated financial statements.

During the year ended December 31, 2005, we incurred approximately $3.8 million in capital expenditures for environmental control equipment, and we estimate we will incur approximately $6.3 million during 2006. We believe these capital expenditures for environmental control equipment will not have a material adverse effect upon our consolidated financial statements.

The Comprehensive Environmental Response, Compensation and Liability Act (known as “Superfund” or “CERCLA”) imposes liability for the release of a “hazardous substance” into the environment. Superfund liability is imposed without regard to fault and even if the waste disposal was in compliance with laws and regulations. We have been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites, and we accrue our share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. With the joint and several liability imposed under Superfund, a PRP may be required to pay more than its proportional share of such costs.

We have been identified as a PRP at various Superfund sites discussed below. The United States Environmental Protection Agency (the “EPA”) and appropriate state agencies supervise investigative and cleanup activities at these sites. For the year ended December 31, 2005, we paid $0.5 million in superfund costs and have accrued an additional $4.9 million related to these sites. Payments made in 2005 are in addition to amounts previously paid in settlements, cash calls or other superfund costs, and these ongoing contributions reduce our financial liability for the total site cleanup costs shown below. When used in the descriptions of the sites that follow, the wordde minimisrefers to the smallest PRPs, whose contribution rate is usually less than 1%.

	(a)		Baker Petrolite, Hughes Christensen, an INTEQ predecessor entity, Baker Oil Tools and a former subsidiary were named in April 1984 as PRPs at the Sheridan Superfund Site located in Hempstead, Texas. The Texas Commission on Environmental Quality (“TCEQ”) is overseeing the remedial work at this site. The Sheridan Site Trust was formed to manage the site remediation and we participate as a member. Based on the use of new remedial technologies, the cost projections remain at $6.0 million for full remediation, of which $5.5 million has been collected. Our additional contribution is approximately 1.8% of the remaining costs.

	(b)		In 1997, we entered into a settlement agreement with Prudential Insurance Company (“Prudential”) regarding cost recovery for the San Fernando Valley — Glendale Superfund. One of our predecessors operated on the Prudential property in Glendale. After Prudential was identified as a PRP for the Glendale Superfund, they instituted legal proceedings against us for cost recovery under CERCLA. Without any admission of liability, we agreed to pay 40% of Prudential’s costs attributed to cleanup at the site, limited to a cap of $0.3 million. A pump and treat system was selected as the cleanup remedy at Glendale, and it is expected to operate until 2012. We continue to contribute our portion of ongoing assessments to fund this remediation strategy.

	(c)		In 1999, the EPA named a Hughes Christensen predecessor as a PRP at the Li Tungsten Site in Glen Cove, New York. We contributed ade minimisamount of hazardous substances to the site. In December 2004, the EPA issued us a specialde minimissettlement offer based on the fact that our contribution was limited to metals contamination, not radiological contamination, at the site. We expect to settle this matter with the EPA for less than $0.1 million.

	(d)		In 1999, Baker Oil Tools, Baker Petrolite and predecessor entities of Baker Petrolite were named as PRPs by the State of California’s Department of Toxic Substances Control for the Gibson site in Bakersfield, California. The most recent cost estimate for remediation of the site is $17.9 million. The combined volume that we contributed to the site is estimated to be less than 0.5% for liquids and 0.25% for solids.

	(e)		In 2001, a Hughes Christensen predecessor, Baker Oil Tools, INTEQ and one of our former subsidiaries were named as PRPs in the Force Road State Superfund Site located in Brazoria County, Texas. The TCEQ is overseeing the investigation and remediation at the Force Road State Site. We participate as a member of the steering and technical committees to effectively manage the project because our volumetric contribution is currently estimated at approximately 76%. The onsite investigation was completed in late 2005, while the offsite investigation is pending access to the adjacent property. The estimate of site remediation costs used for initial settlement purposes was $17.7 million; however, we anticipate that a more accurate calculation of site remediation costs will be possible once the offsite investigation is complete. We believe that after further investigation at the site, negotiation of additional early settlements with other PRPs, future cost recovery actions against recalcitrant parties and other factors, our ultimate share of responsibility for cleanup costs at the site will be less than initial estimates.

	(f)		In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and two of our former subsidiaries were identified as PRPs for the Malone site located on Campbell Bayou Road in Texas City, Texas. The EPA oversees the investigation and remediation of the Malone site and has engaged in emergency removal actions. The investigation is nearly complete and in 2006, remedial options are expected to be developed and submitted to the EPA for evaluation. The estimate for cleanup at the Malone site is $82 million with our contribution estimated at approximately 1.7%. The current owners of the site have filed a lawsuit against the PRPs seeking recovery of certain alleged damages, which may affect the ultimate resolution of this superfund.

	(g)		In 2003, Western Atlas International, Inc., its predecessor companies and Baker Hughes Oilfield Operations, Inc. were identified asde minimisPRPs in the Gulf Nuclear Superfund site in Odessa, Texas. The EPA conducted an emergency removal at the site in 2000. Total investigation and cleanup costs were estimated by the EPA to be approximately $24 million. Thede minimissettlement proposal has been negotiated and should be finalized in 2006. Our settlement cost is expected to be less than $0.1 million.

	(h)		In 2003, we were identified as ade minimisPRP by the EPA for the Operating Industries, Inc. Superfund site in Monterrey Park, California. A settlement offer to all remainingde minimisparties has been repeatedly delayed, but is expected in mid 2006. The EPA and Steering Committee estimate cleanup costs in excess of $650 million. As of January 2006, there was insufficient information to estimate our allocation or potential contribution to these cleanup costs.

	(i)		In 2003, Baker Petrolite was notified by the EPA of their potential involvement at the Cooper Drum Superfund site located in South Gate, California. The company responded to an additional inquiry from the EPA in 2005. At this time there is no estimate available for comprehensive cleanup costs or our allocation and, accordingly, the extent of our financial liability at the site is unknown.

	(j)		In 2004, we were notified that Baker Petrolite was included in the Container Recycling Superfund site in Kansas City, Kansas. We are a PRP at the site, which was a former drum recycler used by a predecessor company to Baker Petrolite. Site remediation has been completed and the EPA has extended a settlement offer of $1.3 million to the PRP group with our allocation calculated at 4% of these costs. Baker Petrolite has signed the settlement offer.

	(k)		In 2005, Centrilift was notified by the TCEQ of their potential involvement in the San Angelo Superfund site in Tom Green County, Texas. Polychlorinated biphenyls (PCBs) are present at the site as a result of the operations of the former San Angelo Electric Services Company (SESCO), which manufactured, repaired and serviced transformers. SESCO declared bankruptcy in mid 2003, after which the TCEQ conducted emergency removal actions in response to reports of contamination onsite and in the adjacent residential area. Ade minimissettlement offer has been received, and our cost contribution for the remediation of soil and groundwater is less than $0.1 million.

In addition to the sites mentioned above, there are four Superfund sites where we have ongoing obligations. The remedial work at most of these sites has been completed and remaining operations are limited to groundwater recovery and/or monitoring. The monitoring phase can continue for up to 30 years. Our aggregate cost for these sites is estimated to be approximately $0.1 million over this period of time.

While PRPs in Superfund actions have joint and several liability for all costs of remediation, it is not possible at this time to quantify our ultimate exposure because some of the projects are either in the investigative or early remediation stage. Based upon current information, we do not believe that probable or reasonably possible expenditures in connection with the sites described above are likely to have a material adverse effect on our consolidated financial statements because we have established adequate reserves to cover the estimate we presently believe will be our ultimate liability in the matter. Further, other PRPs involved in the sites have

substantial assets and may reasonably be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage or contractual indemnities from third parties to cover a portion of or the ultimate liability.

We are subject to various other governmental proceedings and regulations, including foreign regulations, relating to environmental matters, but we do not believe that any of these matters is likely to have a material adverse effect on our consolidated financial statements. We continue to focus on reducing future environmental liabilities by maintaining appropriate company standards and improving our assurance programs. See Note 16 of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of environmental matters.

“Environmental Matters” contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “Forward–Looking Statement”). The words “will,” “believe,” “to be,” “expect,” “estimate” and similar expressions are intended to identify forward–looking statements. Our expectations regarding our compliance with Environmental Regulations and our expenditures to comply with Environmental Regulations, including (without limitation) our capital expenditures for environmental control equipment, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which may be affected by the following factors: changes in Environmental Regulations; a material change in our allocation or other unexpected, adverse outcomes with respect to sites where we have been named as a PRP, including (without limitation) the Superfund sites described above; the discovery of new sites of which we are not aware and where additional expenditures may be required to comply with Environmental Regulations; an unexpected discharge of hazardous materials in the course of our business or operations; a catastrophic event causing discharges into the environment; or an acquisition of one or more new businesses.

ITEM 1A. RISK FACTORS

An investment in our common stock involves various risks. When considering an investment in our company, you should consider carefully all of the risk factors described below, as well as other information included and incorporated by reference in this report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors include those factors that impact, either positively or negatively, the markets for oil and natural gas. Expenditures by our customers for exploration, development and production of oil and natural gas are based on their expectations of future hydrocarbon demand, the risks associated with developing the reserves and the future value of the hydrocarbon reserves. Their evaluation of the future value is based, in part, on their expectations for global demand, global supply and other factors that influence oil and natural gas prices. The key risk factors currently influencing the worldwide oil and natural gas markets are discussed below.

Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.

Growth in worldwide demand for oil and natural gas, as well as the demand for our services, is highly correlated with global economic growth — and in particular by the economic growth of countries such as the U.S. and China, who are significant users of oil and natural gas. Increases in global economic activity, particularly in China and developing Asia, create more demand for oil and natural gas and higher oil and natural gas prices. A slowing of global economic growth, and in particular in the U.S. or China, will likely reduce demand for oil and natural gas, increase excess productive capacity and result in lower prices and adversely impact the demand for our services.

Volatility of oil and natural gas prices can adversely affect demand for our products and services.

Volatility in oil and natural gas prices can also impact our customers’ activity levels and spending for our products and services. While current energy prices are important contributors to positive cash flow for our customers, expectations about future prices and price volatility are generally more important for determining future spending levels. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our results of operations.

Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.

Productive capacity for oil and natural gas is dependent on our customers’ decisions to develop and produce oil and natural gas reserves. The ability to produce oil and natural gas can be affected by the number and productivity of new wells drilled and completed, as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling, improve total recovery but also result in a more rapid production decline.

Access to prospects and capital are also important to our customers. Access to prospects may be limited because host governments do not allow access to the reserves or because another oil and natural gas exploration company owns the rights to develop the prospect. Access to capital is dependent on our customers’ ability to access the funds necessary to develop economically attractive projects based on their expectations of future energy prices, required investments and resulting returns. Government regulations and the costs incurred by oil and natural gas exploration companies to conform to and comply with government regulations, may also limit the quantity of oil and natural gas that may be economically produced.

Supply can be interrupted by a number of factors including political instability, civil unrest, labor issues, terrorist attacks, war or military activity. Key oil producing countries which could be subject to supply interruptions include, but are not limited to, Saudi Arabia, Iran, Iraq and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela. The impact of supply and demand disruptions on oil and natural gas prices and oil and natural gas price volatility is tempered by the size and expected duration of the disruption relative to the excess productive capacity at the time of the disruption.

Supply can also be impacted by the degree to which individual Organization of Petroleum Exporting Countries (“OPEC”) nations and other large oil and natural gas producing countries, including, but not limited to, Mexico, Norway and Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support their targeted oil price while meeting their market share objectives. Any of these factors could affect the supply of oil and natural gas and could have a material adverse effect on our results of operations.

Excess productive capacity and future demand impact our operations.

Oil and natural gas storage inventory levels are an indicator of the relative balance between supply and demand. High or increasing storage or inventories generally indicate that supply is exceeding demand and that energy prices are likely to soften. Low or decreasing storage or inventories are an indicator that demand is growing faster than supply and that energy prices are likely to rise. Measures of maximum productive capacity compared to demand (“excess productive capacity”) are also an important factor influencing energy prices and spending by oil and natural gas exploration companies. When excess productive capacity is low compared to demand, energy prices tend to be higher and more volatile reflecting the increased vulnerability of the entire system to disruption.

Seasonal and adverse weather conditions adversely affect demand for our services and operations.

Weather can also have a significant impact on demand as consumption of energy is seasonal and any variation from normal weather patterns, cooler or warmer summers and winters, can have a significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of Mexico, may interrupt or curtail our operations, or our customers’ operations, cause supply disruptions and result in a loss of revenue and damage to our equipment and facilities, which may or may not be insured.

Risk Factors Related to Our Business

Our expectations regarding our business are affected by the following risk factors and the timing of any of these risk factors:

We operate in a highly competitive environment, which may adversely affect our ability to succeed.

We operate in a highly competitive environment for marketing oil and natural gas and securing equipment and trained personnel. Our ability to continually provide competitive products and services can impact our ability to maintain or increase prices for our products and services, maintain market share and negotiate acceptable contract terms with our customers. In order to be competitive, we must provide new technologies, and reliable products and services that perform as expected and that create value for our customers. Our ability to maintain or increase prices for our products and services is in part dependent on the industry’s capacity relative to customer demand, and on our ability to differentiate the value delivered by our products and services from our competitor’s products and services. In addition, our ability to negotiate acceptable contract terms and conditions with our customers, especially state–owned national oil companies, our ability to manage warranty claims and our ability to effectively manage our commercial agents can also impact our results of operations.

Managing development of competitive technology and new product introductions on a forecasted schedule and at forecasted costs can impact our financial results. Development of competing technology that accelerates the obsolescence of any of our products or services can have a detrimental impact on our financial results and can result in the potential impairment of long-lived assets.

We may be disadvantaged competitively and financially by a significant movement of exploration and production operations to areas of the world in which we are not currently active.

The high cost or unavailability of materials, equipment, supplies and personnel could adversely affect our ability to execute our operations on a timely basis.

Our manufacturing operations are dependent on having sufficient raw materials, component parts and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while minimizing inventories. Our ability to effectively manage our manufacturing operations and meet these goals can have an impact on our business, including our ability to meet our manufacturing plans and revenue goals, control costs and avoid shortages of raw materials and component parts. Raw materials and components of particular concern include steel alloys, copper, carbide, chemicals and electronic components. Our ability to repair or replace equipment damaged or lost in the well can also impact our ability to service our customers.

People are a key resource to developing, manufacturing and delivering our products and services to our customers around the world. Our ability to recruit, train and retain the highly skilled workforce required by our plans will impact our business. A well-trained, motivated work force has a positive impact on our ability to attract and retain business. Rapid growth presents a challenge to us and our industry to recruit, train and retain our employees while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate. Labor-related actions, including strikes, slowdowns and facility occupations can also have a negative impact on our business.

Compliance with and changes in laws and regulations and risks from investigations and legal proceedings could be costly and could adversely affect operating results.

Our operations in the U.S. and over 90 countries can be impacted by expected and unexpected changes in the legal and business environments in which we operate, as well as the outcome of ongoing government and internal investigations and legal proceedings.

Changes that could impact the legal environment include new legislation, new regulation, new policies, investigations and legal proceedings and new interpretations of the existing legal rules and regulations. In particular, changes in export control laws or exchange control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in Russia or other countries identified by management for immediate focus. Changes that impact the business environment include changes in accounting standards, changes in environmental laws, changes in tax laws or tax rates, the resolution of audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards and tax credits. Compliance related issues could limit our ability to do business in certain countries.

These changes could have a significant financial impact on our future operations and the way we conduct, or if we conduct, business in the affected countries.

Uninsured claims and litigation could adversely impact our operating results.

We have insurance coverage against operating hazards, including product liability claims and personal injury claims related to our products, to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future claims and litigation. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. Whenever possible, we obtain agreements from customers that limit our liability. Insurance and customer agreements do not provide complete protection against losses and risks, and our results of operations could be adversely affected by unexpected claims not covered by insurance.

Compliance with and rulings and litigation in connection with environmental regulations may adversely affect our business and operating results.

Our business is impacted by unexpected outcomes or material changes in environmental liability. Changes in our environmental liability could originate with the discovery of new environmental remediation sites, changes in environmental regulations, or the discharge of hazardous materials or oil and natural gas into the environment.

Changes in economic conditions and currency fluctuations may adversely affect our operating results.

Fluctuation in foreign currencies relative to the U.S. Dollar can impact our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars or local currency indexed to U.S. Dollars. Local expenses and some of our manufacturing costs are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign currencies, particularly the British Pound Sterling, Euro, Canadian Dollar, Norwegian Krone, Venezuelan Bolivar, Australian Dollar and Brazilian Real, can increase or decrease our U.S. Dollar expenses and impact our operating margins. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non–functional currency, are included in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and losses resulting from balance sheet translation of foreign operations are also included in the consolidated statements of operations as incurred. Such transaction and translation losses may adversely impact our results of operations.

The condition of the capital markets and equity markets in general can affect the price of our common stock and our ability to obtain financing, if necessary. If the Company’s credit rating is downgraded, this would increase our costs under our credit agreement, as well as the cost of obtaining, or make it more difficult to obtain or issue, new debt financing.

Our ability to forecast the size of and changes in the worldwide oil and natural gas industry and our ability to forecast our customers’ activity levels and demand for our products and services impacts our management of our manufacturing and distribution activities, our staffing levels and our cash and financing requirements. Unanticipated changes in our customers’ requirements can impact our costs, creating temporary shortages or surpluses of equipment and people and demands for cash or financing.

The market price of our common stock may fluctuate.

Historically, the market price of common stock of companies engaged in the oil and natural gas industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past. News announcements and changes in oil and natural gas prices, changes in the demand for oil and natural gas exploration and changes in the supply and demand for oil and natural gas have all been factors that have affected the price of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We are headquartered in Houston, Texas and operate 42 principal manufacturing plants, ranging in size from approximately 5,000 to 333,000 square feet of manufacturing space. The total area of the plants is approximately 3.2 million square feet, of which approximately 2.1 million square feet (65%) are located in the United States, 0.3 million square feet (11%) are located in Canada and South America, 0.7 million square feet (22%) are located in Europe, and a minimal amount of space is located in the Far East. Our principal manufacturing plants are located as follows: United States — Houston, Texas; Broken Arrow and Claremore, Oklahoma; Lafayette, Louisiana; South America — various cities in Venezuela; and Europe — Aberdeen and East Kilbride, Scotland; Liverpool, England; Celle, Germany; Belfast, Northern Ireland.

We own or lease numerous service centers, shops and sales and administrative offices throughout the geographic areas in which we operate. We also have a significant investment in service vehicles, rental tools and manufacturing and other equipment. We believe that our manufacturing facilities are well maintained and suitable for their intended purposes. The table below shows our principal manufacturing plants by segment and geographic area:


			Canada
			and
Segment	United States		South America		Europe		Far East		Total

Completion and Production		16		4		5		1		26

Drilling and Evaluation		12		1		3		—		16

ITEM 3. LEGAL PROCEEDINGS

We are involved in litigation or proceedings that have arisen in our ordinary business activities. We insure against these risks to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future legal proceedings. Many of these insurance policies contain deductibles or self–insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self–insurance, it is our policy to self–insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation. We record accruals for the uninsured portion of losses related to these types of claims. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

On September 12, 2001, we, without admitting or denying the factual allegations contained in the Order, consented with the Securities and Exchange Commission (“SEC”) to the entry of an Order making Findings and Imposing a Cease–and–Desist Order (the “Order”) for violations of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Exchange Act. Among the findings included in the Order were the following: In 1999, we discovered that certain of our officers had authorized an improper $75,000 payment to an Indonesian tax official, after which we embarked on a corrective course of conduct, including voluntarily and promptly disclosing the misconduct to the SEC and the Department of Justice (the “DOJ”). In the course of our investigation of the Indonesia matter, we learned that we had made payments in the amount of $15,000 and $10,000 in India and Brazil, respectively, to our agents, without taking adequate steps to ensure that none of the payments would be passed on to foreign government officials. The Order found that the foregoing payments violated Section 13(b)(2)(A). The Order also found us in violation of Section 13(b)(2)(B) because we did not have a system of internal controls to determine if payments violated the Foreign Corrupt Practices Act (“FCPA”). The FCPA makes it unlawful for U.S. issuers, including us, or anyone acting on their behalf, to make improper payments to any foreign official in order to obtain or retain business. In addition, as discussed below, the FCPA establishes accounting and internal control requirements for U.S. issuers. We cooperated with the SEC’s investigation.

By the Order, dated September 12, 2001 (previously disclosed by us and incorporated by reference in this annual report as Exhibit 99.1), we agreed to cease and desist from committing or causing any violation and any future violation of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Exchange Act. Such Sections of the Exchange Act require issuers to: (x) make and keep books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and maintain a system of internal accounting controls sufficient to provide reasonable assurances that: (i) transactions are executed in accordance with management’s general or specific authorization; and (ii) transactions are recorded as necessary: (I) to permit preparation of financial statements in conformity with generally accepted accounting principles or any other criteria applicable to such statements, and (II) to maintain accountability for assets.

On March 29, 2002, we announced that we had been advised that the SEC and the DOJ are conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding anti–bribery, books and records and internal controls. The SEC has issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In addition, we have conducted internal investigations into these matters.

Our internal investigations have identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental authorities in Nigeria. The internal investigation in Nigeria was substantially completed during the first quarter of 2003, and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our consolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the internal investigations has been provided to the SEC and DOJ.

The Department of Commerce, Department of the Navy and DOJ (the “U.S. agencies”) have investigated compliance with certain export licenses issued to Western Geophysical from 1994 through 2000 for export of seismic equipment leased by the People’s Republic of China. We acquired Western Geophysical in August 1998 and subsequently transferred related assets to WesternGeco in December 2000. WesternGeco continued to use the licenses until 2001. Under the WesternGeco Formation Agreement, we owe indemnity to WesternGeco for certain matters and, accordingly, we have agreed to indemnify WesternGeco with certain limitations in connection with this matter. We are cooperating fully with the U.S. agencies.

We have received a subpoena from a grand jury in the Southern District of New York regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations Oil–for–Food Program. We have also received a request from the SEC to provide a written statement and certain information regarding our participation in that program. We have responded to both the subpoena and the request and may provide additional information and documents in the future. Other companies in the energy industry are believed to have received similar subpoenas and requests.

The U.S. agencies, the SEC and other authorities have a broad range of civil and criminal sanctions they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Such agencies and authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed, including in some cases multi–million dollar fines and other sanctions. We are in discussions with the U.S. agencies and the SEC regarding the resolution, including sanctions, associated with certain of the matters described above. It is not possible to accurately predict at this time when any of these matters will be resolved. Based on current information, we cannot predict the outcome of such investigations, whether we will reach resolution through such discussions or what, if any, actions may be taken by the U.S. agencies, the SEC or other authorities or the effect the actions may have on our consolidated financial statements.

On May 10, 2004, the District Court of Andrews County, Texas entered a judgment in favor of LOTUS, LLC and against INTEQ in the amount of $14.8 million for lost profits resulting from a breach of contract in drilling a well to create a salt cavern for disposing of naturally occurring radioactive waste. We have filed an appeal and taken other actions. We believe that any liability that we may incur as a result of this litigation would not have a material adverse financial effect on our consolidated financial statements.

Further information is contained in the “Environmental Matters” section of Item 1 herein.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock, $1.00 par value per share, is principally traded on the New York Stock Exchange. Our common stock is also traded on the SWX Swiss Exchange. As of February 24, 2006, there were approximately 88,700 stockholders and approximately 16,200 stockholders of record.

For information regarding quarterly high and low sales prices on the New York Stock Exchange for our common stock during the two years ended December 31, 2005, and information regarding dividends declared on our common stock during the two years ended December 31, 2005, see Note 18 of the Notes to Consolidated Financial Statements in Item 8 herein.

The following table contains information about our purchases of equity securities during the fourth quarter of 2005.

Issuer Purchases of Equity Securities


			Total Number				Maximum Number (or
			of Shares				Approximate Dollar
	Total Number		Purchased as		Average		Value) of Shares that
	of Shares		Part of a Publicly		Price Paid		May Yet Be Purchased
Period	Purchased		Announced Program⁽¹⁾		per Share⁽²⁾		Under the Program⁽¹⁾
October 1–31, 2005		—		—	$	—		—
November 1–30, 2005		—		888,200		55.66		—
December 1–31, 2005		—		805,900		60.93		—

Total		—		1,694,100	$	58.17		—


⁽¹⁾		On September 10, 2002, we announced a program to repurchase from time to time up to $275.0 million of our outstanding common stock. On October 27, 2005, we had authorization remaining to repurchase up to $44.5 million in common stock and we announced that the Board of Directors authorized us to repurchase up to an additional $455.5 million of our common stock from


		time to time. As of December 31, 2005, we now have authorization remaining to repurchase up to a total of $401.5 million of our common stock. The program has no expiration date, but may be terminated by the Board of Directors at any time.

		On November 3, 2005, we entered into a Stock Purchase Plan with an agent for the purchase of shares of our common stock that complies with the requirements of Rule 10b5–1 promulgated by the Securities Exchange Act of 1934. The term of the November Plan will run from November 7, 2005 until April 30, 2006, unless earlier terminated. On February 22, 2006, we entered into another Plan for a term that will run from February 23, 2006 until April 30, 2006, unless earlier terminated. During that term, the agent will use its best efforts to repurchase a fixed dollar value of our common stock each trading day, subject to applicable trading rules, until the cumulative amount purchased under the November Plan equals $250.0 million and under the February Plan equals $150.0 million, inclusive of all commissions and fees paid by us to the agent related to such repurchases. Shares will be repurchased by the agent at the prevailing market prices, subject to limitations provided by us, in open market transactions intended to comply with Rule 10b–18 of the Exchange Act. We or the agent may terminate the Plans. However, no shares will be repurchased at any time that the cost of the shares exceeds an amount that has been specified by us to the agent.

⁽²⁾		Average price paid includes commissions.

ITEM 6. SELECTED FINANCIAL DATA

The Selected Financial Data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.


	Year Ended December 31,
(In millions, except per share amounts)	2005			2004			2003			2002			2001

Revenues	$	7,185.5		$	6,079.6		$	5,233.3		$	4,843.5		$	4,980.5
Costs and expenses:
Cost of revenues		4,942.5			4,351.0			3,807.5			3,478.5			3,519.1
Selling, general and administrative		1,009.6			912.2			824.6			805.5			748.3
Impairment of investment in affiliate		—			—			45.3			—			—
Restructuring charge reversals		—			—			(1.1	)		—			(4.2	)
Gain on disposal of assets		—			—			—			—			(2.4	)

Total costs and expenses		5,952.1			5,263.2			4,676.3			4,284.0			4,260.8

Operating income		1,233.4			816.4			557.0			559.5			719.7
Equity in income (loss) of affiliates		100.1			36.3			(137.8	)		(69.7	)		45.8
Interest expense		(72.3	)		(83.6	)		(103.1	)		(111.1	)		(126.3	)
Interest income		18.0			6.8			5.3			5.2			11.7

Income from continuing operations before income taxes		1,279.2			775.9			321.4			383.9			650.9
Income taxes		(404.8	)		(250.6	)		(145.6	)		(157.9	)		(221.7	)

Income from continuing operations		874.4			525.3			175.8			226.0			429.2
Income (loss) from discontinued operations, net of tax		4.9			3.3			(41.3	)		(14.6	)		9.5

Income before extraordinary loss and cumulative effect of accounting change		879.3			528.6			134.5			211.4			438.7
Extraordinary loss, net of tax		—			—			—			—			(1.5	)
Cumulative effect of accounting change, net of tax		(0.9	)		—			(5.6	)		(42.5	)		0.8

Net income	$	878.4		$	528.6		$	128.9		$	168.9		$	438.0


Per share of common stock:
Income from continuing operations:
Basic	$	2.58		$	1.57		$	0.52		$	0.67		$	1.28
Diluted		2.56			1.57			0.52			0.67			1.27
Dividends		0.475			0.46			0.46			0.46			0.46

Financial Position:
Working capital	$	2,479.4		$	1,738.3		$	1,210.5		$	1,498.6		$	1,661.6
Total assets		7,807.4			6,821.3			6,416.5			6,499.7			6,676.2
Long–term debt		1,078.0			1,086.3			1,133.0			1,424.3			1,682.4
Stockholders’ equity		4,697.8			3,895.4			3,350.4			3,397.2			3,327.8

NOTES TO SELECTED FINANCIAL DATA


(1)		Discontinued operations.The selected financial data includes reclassifications to reflect Baker Supply Products Division, Baker Hughes Mining Tools, BIRD Machine, EIMCO Process Equipment and our oil producing operations in West Africa as discontinued operations. See Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding discontinued operations.

(2)		Impairment of investment in affiliate.See Note 8 of the Notes to Consolidated Financial Statements in Item 8 herein for a description of the $45.3 million impairment of our investment in WesternGeco in 2003 and for a description of the impairment and restructuring charges of $135.7 million recorded in equity in income (loss) of affiliates in 2003, also related to WesternGeco. Included in equity in income (loss) of affiliates for 2002 is $90.2 million for our share of a $300.7 million restructuring charge related to WesternGeco’s impairment of assets, reductions in workforce, closing certain operations and reducing its marine seismic fleet.

(3)		Restructuring charge reversals.See Note 4 of the Notes to Consolidated Financial Statements in Item 8 herein for a description of the restructuring charge reversal in 2003. During 2000, we recorded a restructuring charge of $29.5 million related to our plan


		to substantially exit the oil and natural gas exploration business. Included in the restructuring charge were costs to settle contractual obligations of $4.5 million for the minimum amount of our share of project costs relating to our interest in an oil and natural gas property in Colombia. After unsuccessful attempts to negotiate a settlement with our joint venture partner, we decided to abandon further involvement in the project. Subsequently, in 2001, a third party agreed to assume the remaining obligation in exchange for our interest in the project. Accordingly, we reversed $4.2 million related to this obligation.

(4)		Cumulative effect of accounting change.In 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations. In 2003, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations. In 2002, we adopted SFAS No. 142,Goodwill and Other Intangible Assets. In 2001, we adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and 138.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the consolidated financial statements of “Item 8. Financial Statements and Supplementary Data” contained herein.

EXECUTIVE SUMMARY

We are a leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We compete as one of the three largest diversified oilfield services companies. In early 2005, we organized our product-line focused divisions into two separate segments: the Drilling and Evaluation segment and the Completion and Production segment. The segments are aligned by product line based on the types of products and services provided to our customers and on the business characteristics of the divisions during business cycles. Activity of the businesses under the Drilling and Evaluation segment is closely correlated to rig counts and, therefore, is prone to cyclicality as drilling activity increases or decreases. Activity of businesses in the Completion and Production segment is more dependent on production volumes and, therefore, is less cyclical than the Drilling and Evaluation segment. We also own a 30% equity interest in WesternGeco, a seismic venture with Schlumberger Limited (“Schlumberger”). Accordingly, we report our results under three segments - Drilling and Evaluation, Completion and Production and WesternGeco:

	•		The Drilling and Evaluation segment consists of Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (conventional and rotary directional drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services). The Drilling and Evaluation segment provides products and services used to drill oil and natural gas wells.

	•		The Completion and Production segment consists of Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electric submersible pumps and progressing cavity pumps). The Completion and Production segment also includes our Production Optimization business unit (permanent downhole monitoring). The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

	•		The WesternGeco segment consists of our equity interest in WesternGeco.

Also in 2005, we organized the business operations of our divisions around four primary geographic regions: North America, Latin America, Middle East/Asia Pacific, and Europe, Africa, Russia and the Caspian. Each region has a council comprised of regional vice presidents from each division as well as representatives from various functions such as human resources, legal, marketing and health, safety and environmental. The regional vice presidents report directly to each division president. Through this structure, we have placed our management closer to the customer, improving our customer relationships and allowing us to react more quickly to local market conditions and needs.

Our headquarters are in Houston, Texas, and we have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), Scotland (Aberdeen and East Kilbride), Germany (Celle), Northern Ireland (Belfast) and Venezuela (Maracaibo). We operate in over 90 countries around the world and employ approximately 29,100 employees — about one-half of which work outside the U.S. Our revenue in 2005 was $7.2 billion — approximately 36% of which came from providing products and services to oil and natural gas companies operating in the U.S.

During 2005, the Baker Hughes worldwide rig count continued to increase, as oil and natural gas companies around the world recognized the need to build productive capacity to meet the growing demand for hydrocarbons and to offset depletion of existing developed reserves. Oil and natural gas prices were at historic highs in 2005, reflecting continued strong demand, relatively low excess productive capacity, and disruptions in supply due to hurricanes in the Gulf of Mexico. We reported revenues of $7,185.5 million for 2005, an 18.2% increase compared with 2004, approximating the 14.8% increase in the worldwide average rig count for 2005 compared with 2004. In addition to the growth in our revenues from increased activity, our revenues were impacted by pricing improvements and changes in market share in certain product lines. Net income for 2005 was $878.4 million, a 66.2% increase compared with $528.6 million in 2004.

	•		North American revenues increased 20.9% in 2005 compared with 2004, while the rig count increased 18.0% for 2005 compared with 2004, driven primarily by land-based drilling for natural gas. In 2005, hurricane-related disruptions negatively impacted our revenues from the U.S. offshore market by approximately $68.0 million.

	•		Latin American revenues increased 15.3% and the Latin American rig count increased 9.0% in 2005 compared with 2004.

	•		Europe, Africa, Russia and the Caspian revenues increased 14.0% in 2005 compared with 2004. Growth in revenues from Europe and Africa exceeded the increase in the rig counts for both regions for the comparable periods.

	•		Middle East and Asia Pacific revenues were up 20.2% in 2005 compared with 2004. Revenue from the Middle East was up 20.5% compared to a rig count which increased 7.4% and Asia Pacific revenue was up 20.0% compared to a rig count which increased 14.2%.

The customers for our products and services include the super-major and major integrated oil and natural gas companies, independent oil and natural gas companies and state-owned national oil companies (“NOCs”). Our ability to compete in the oilfield services market is dependent on our ability to differentiate our product and service offerings by technology, service and the price paid for the value we deliver.

The primary driver of our business is our customers’ capital and operating expenditures dedicated to exploring and drilling for and developing and producing oil and natural gas. Our business is cyclical and is dependent upon our customers’ forecasts of future oil and natural gas prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas production. During 2005, our customers’ spending directed to both worldwide oil and North American oil and natural gas projects increased compared with 2004. The increase in spending was driven by the multi-year requirement to find, develop and produce more hydrocarbons to meet the growth in demand, offset production declines, increase inventory levels and rebuild productive capacity. Additionally, the increase was supported by historically high oil and natural gas prices. Our customers’ spending on oil and gas projects is expected to continue to grow through 2006.

The critical success factors for our business are embodied in our long-term strategy, which we call our Strategic Framework. This strategy includes the development and maintenance of a high performance culture founded on our Core Values; our product line focused organization and our focus on Best-in-Class opportunities; maintaining our financial flexibility and financial discipline; and execution of our strategies for product development and commercialization, manufacturing quality and service quality.

Our ongoing effort to develop and maintain a high performance culture starts with our Core Values of integrity, teamwork, performance and learning. We employ succession planning efforts to develop leaders across all our businesses that embody these Core Values and represent the diversity of our customer base. We hire and train employees from around the world to ensure that we have a well-trained workforce in place to support our business plans.

Our focus on Best-in-Class opportunities starts with our product line focused organization structure. We believe that through our product line focused divisions, we develop the technologies that deliver Best-in-Class value to our customers. As an enterprise, we are also focused on those markets that we believe provide Best-in-Class opportunities for growth. Our management team has identified markets for immediate focus including the Middle East, Russia and the Caspian region and NOCs.

Our focus on financial flexibility and financial discipline is the backbone of our effort to deliver differential growth at superior margins while earning an acceptable return on our investments throughout the business cycle. Investments are given priority and funded depending on their ability to provide risk-adjusted returns in excess of our cost of capital. Our effort to obtain the best price for our products and services begins with our approach to capital discipline. Over the past few years, we have invested for growth in our business, repaid debt, paid dividends and repurchased stock, and we expect to maintain the flexibility to undertake such activities in the future.

The last element of our Strategic Framework focuses on our ability to identify, develop and commercialize new products and services that will lead to differential growth at superior margins in our business. The effort extends to every phase of our operations, including continuous improvement programs in our manufacturing facilities and field operations that support our goal of flawless execution at the well site.

The execution of our 2006 business plan and the ability to meet our 2006 financial objectives are dependent on a number of factors. These factors include, but are not limited to, our ability to: recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; realize price increases commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; expand our business in areas that are growing rapidly with customers whose spending is expected to increase substantially (such as NOCs), and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian region); manage increasing raw material and component costs (especially steel alloys, copper, carbide, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization.

For a full discussion of risk factors and forward-looking statements, please see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration and production (“E&P”) of oil and natural gas reserves. An indicator for this spending is the rig count, because when drilling and workover rigs are active, many of the products and services provided by the oilfield services industry are required. Our products and services are used during the drilling and workover phases, during the completion of oil and natural gas wells and during actual production of the hydrocarbons. This E&P spending by oil and natural gas companies is, in turn, influenced strongly by expectations about the supply and demand for oil and natural gas products and by current and expected prices for both oil and natural gas. Rig counts, therefore, generally reflect the relative strength and stability of energy prices.

Rig Counts

We have been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors or other outside sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, onshore China and other countries, because this information is extremely difficult to obtain or we do not have local resources to make an accurate count.

Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started, drilling has not been completed and the well is anticipated to be of sufficient depth, which may change from time to time and may vary from region to region, and is expected to be a potential consumer of our drill bits. In general, rigs are counted as active if the well has been started but has not reached its target depth, even if there are extensive delays due to weather or other reasons. If the well has been started but not completed and the rig is expected to resume work in two weeks or less, the rig is counted as active during a weather delay. Rigs are not typically counted as active if the rig is lost or damaged or if drilling operations are expected to be suspended for more than two weeks.

Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most other international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, a weekly or daily average of active rigs is taken. In those international areas where there is poor availability of data, the rig counts are estimated or quoted from third party data.

The rig count does not include rigs that are in transit from one location to another, are rigging up, are being used in non-drilling activities, including production testing, completion and workover, or are not, in our opinion, deemed to be a potential user of our drill bits.

Our rig counts are summarized in the table below as averages for each of the periods indicated.


	2005		2004		2003

U.S. — land and inland waters		1,290		1,095		924
U.S. — offshore		93		97		108
Canada		455		365		372

North America		1,838		1,557		1,404

Latin America		316		290		244
North Sea		43		39		46
Other Europe		27		31		38
Africa		50		49		54
Middle East		247		230		211
Asia Pacific		225		197		177

Outside North America		908		836		770

Worldwide		2,746		2,393		2,174

U.S. Workover Rigs		1,356		1,235		1,129

The U.S. land and inland waters rig count increased 17.8% in 2005 compared with 2004, due to the increase in drilling for natural gas. The U.S. offshore rig count decreased 4.1% in 2005 compared with 2004, reflecting the activity disruptions caused by hurricanes in the Gulf of Mexico in the third quarter of 2005. The Canadian rig count increased 24.7% due to the increase in drilling for natural gas.

Outside North America, the rig count increased 8.6% in 2005 compared with 2004. The rig count in Latin America increased 9.0% in 2005 compared with 2004, driven primarily by activity increases in Venezuela, Colombia and Argentina. The North Sea rig count increased 10.3% in 2005 compared with 2004. The rig count in Africa increased by 2.0% in 2005 compared with 2004. Activity in the Middle East continued to rise steadily, with a 7.4% increase in the rig count in 2005 compared with 2004, driven primarily by activity increases in Saudi Arabia, Qatar, Sudan and Yemen. The rig count in the Asia Pacific region was up 14.2% in 2005 compared with 2004, primarily due to activity increases in India, Indonesia, offshore China and Thailand.

Oil and Natural Gas Prices

Generally, changes in the current price and expected future prices of oil or natural gas drive both customers’ expectations about their prospects from oil and natural gas sales and their expenditures to explore for or produce oil and natural gas. Accordingly, changes in these expenditures will normally result in increased or decreased demand for our products and services. Oil (Bloomberg West Texas Intermediate (WTI) Cushing Crude Oil Spot Price) and natural gas (Bloomberg Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.


	2005		2004		2003

Oil prices ($/Bbl)	$	56.59	$	41.51	$	31.06
Natural gas prices ($/mmBtu) *		8.66		5.90		5.49


*		In late September 2005, Hurricane Rita damaged natural gas processing facilities in Henry, Louisiana (“Henry Hub”) and the New York Mercantile Exchange declaredforce majeureon its Henry Hub natural gas contracts. As a result, the average natural gas prices for 2005 exclude price data for September 22, 2005 through October 6, 2005 when there was insufficient activity to determine a spot price.

Oil prices averaged a historic high of $56.59/Bbl in 2005. Prices increased from the low $40s/Bbl in January 2005 to a high of almost $70/Bbl in late September 2005, before moderating and ending the year in the low $60s/Bbl. Between mid-August and the end of September oil prices traded between $60/Bbl and $70/Bbl primarily due to the disruptive impact of hurricanes in the Gulf of Mexico. Worldwide demand for hydrocarbons was driven by strong worldwide economic growth, which was particularly strong in China and developing Asia. Worldwide excess productive capacity was at the lowest level in 30 years, and disruptions, or the potential for disruptions, in oil supply resulted in volatile oil prices throughout the year.

During 2005, natural gas prices averaged a historic high of $8.66/mmBtu. Throughout the first seven months of 2005, a tight balance between supply and demand supported prices between $5.50/mmBtu and $8/mmBtu. In the last five months of 2005, natural gas was extremely volatile trading between $9/mmBtu and $15/mmBtu due to supply disruptions caused by Gulf of Mexico hurricanes and supported by high oil prices.

Worldwide Oil and Natural Gas Industry Outlook

This section should be read in conjunction with the factors described in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

Oil— Average oil prices in 2006 are expected to be between $55/Bbl and $75/Bbl. Strong worldwide economic growth and the lack of excess productive capacity are expected to support prices within this range. Growth in oil demand is expected to increase in 2006 compared with 2005, as worldwide economic growth and, in particular, economic growth in China is expected to continue to grow in 2006. At the beginning of December 2005, the International Energy Agency estimated that excess productive capacity was less than 3% of demand and that more than three-quarters of the excess capacity was in Saudi Arabia and Iraq. The ongoing lack of excess productive capacity will leave the energy markets susceptible to price volatility and the Organization of Petroleum Exporting Countries (“OPEC”) is unlikely to be able to rapidly increase production should there be any significant disruptions or threat of disruptions in oil supplies.

Factors that could lead to prices at the lower end of this range include, but are not limited to: (1) a significant slowing of worldwide economic growth, particularly economic growth in China; (2) increases in Russian oil exports; (3) any significant disruption to demand; or (4) other factors that result in excess productive capacity and higher oil inventory levels or decreased demand. Factors that could lead to prices at the higher end of this range include, but are not limited to: (1) more rapid than planned expansion of the worldwide economy, particularly the economy in China; (2) a significant slowing of exports from Russia and the inability of key exporting countries to produce additional crude; or (3) other factors that result in excess productive capacity remaining at low levels.

Factors that could lead to disruptions or the threat of disruptions in oil supply and volatility in oil prices include, but are not limited to: (1) terrorist attacks targeting oil production from Saudi Arabia or other key producers; (2) labor strikes in key oil producing areas such as Nigeria; (3) the potential for other military actions in the Middle East; or (4) adverse weather conditions, especially in the Gulf of Mexico. The potential for these and other events to cause volatility will be mitigated by the degree to which OPEC and, in particular, Saudi Arabia are able to increase excess productive capacity as well as the capability of the markets to refine and market products refined from crude oil.

Natural Gas —Natural gas prices in 2006 are expected to remain volatile, averaging between $6/mmBtu and $15/mmBtu. A significant factor for the markets will be the pace of recovery of production of natural gas in the Gulf of Mexico following the disruptions from hurricanes in the Gulf of Mexico in 2005.

Natural gas prices could trade at the top, or beyond the top, of this range if: (1) storage levels are relatively low at the beginning of the withdrawal season; (2) winter weather is colder than normal or summer weather is warmer than normal; (3) we experience slower than expected restoration of hurricane damaged production facilities; or (4) the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of oilfield customer spending are not sufficient to support the production growth required to meet the growth of natural gas demand. Natural gas prices could move to the bottom, or below the bottom, of this range if: (1) storage levels are relatively high at the beginning of the injection season; (2) U.S. economic growth is weaker than expected; or (3) weather is milder than expected.

Customer Spending— Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices described above, anticipated customer spending trends are as follows:

	•		North America — Customer spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 18% to 22% in 2006 compared with 2005.

	•		Outside North America — Customer spending, primarily directed at developing oil supplies, is expected to increase approximately 16% to 20% in 2006 compared with 2005.

	•		Total spending is expected to increase approximately 17% to 21% in 2006 compared with 2005.

Drilling Activity— Based upon our outlook for oil and natural gas prices and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count, is as follows:

•

Drilling activity in North America is expected to increase approximately 12% to 14% in 2006 compared with 2005.

•

Drilling activity outside of North America is expected to increase approximately 8% to 10% in 2006 compared with 2005, excluding Iran and Sudan.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

For discussion of our risk factors and cautions regarding forward-looking statements, see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein. The risk factors discussed there are not intended to be all inclusive.

BUSINESS OUTLOOK

This section should be read in conjunction with the factors described in the “Risk Factors Related to Our Business,” “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward-Looking Statements” sections contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

In our outlook for 2006, we took into account the factors described herein. Revenues in 2006 are expected to increase by approximately 19% to 21%, in line with the expected increase in customer spending. We expect the growth in our revenues will primarily be due to increased activity and pricing improvement. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China, resulting in an average oil price exceeding $50/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding an average of $8/mmBtu.

In North America, we expect revenues to increase approximately 21% to 23% in 2006 compared with 2005. We expect spending on land-based projects to continue to increase in 2006 driven by demand for natural gas, following the trend evident in 2005. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2006 compared with 2005. The normal weather-driven seasonal decline in U.S. and Canadian spending in the first half of the year should result in sequentially softer revenues in the first and second quarters of 2006.

In 2005, 2004 and 2003, revenues outside North America were 57.6%, 58.5% and 57.9% of total revenues, respectively. In 2006, we expect revenues outside North America to continue to be between 55% and 60% of total revenues, and we expect these revenues to increase approximately 18% to 21% in 2006 compared with 2005, continuing the multi-year trend of growth in customer spending. Spending on large projects by NOCs is expected to reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. In addition, customer spending should be affected by weather-related reductions in the North Sea in the first and second quarters of 2006. The Middle East, Africa and Latin America regions are expected to grow modestly in 2006 compared with 2005. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

In 2005, WesternGeco contributed $96.7 million of equity in income of affiliates compared with $34.5 million of equity in income of affiliates in 2004. We expect the trend of improving operating results for WesternGeco to continue throughout 2006. Information regarding WesternGeco’s profitability in 2006 is based on information that WesternGeco has provided to us. Should this information not be accurate, our forecasts for profitability could be impacted, either positively or negatively.

Based on the above forecasts, we believe net income per diluted share in 2006 will be in the range of $3.40 to $3.60, which includes the impact of expensing stock option awards and stock issued under the employee stock purchase plan of between $18.0 million and $20.0 million, net of tax. Significant price increases, lower than expected raw material and labor costs, higher than planned activity or significantly better than expected results from WesternGeco could cause earnings per share to reach the upper end of this range. Conversely, less than expected price increases, higher than expected raw material and labor costs, lower than expected productivity or significantly worse than expected results at WesternGeco could result in earnings per share being at or below the bottom of this range. Our ability to improve pricing is dependent on demand for our products and services and our competitors strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing pricing improvement, without pricing discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized. Additionally, significant changes in drilling activity outside our expectations could impact operating results positively or negatively.

We do business in approximately 90 countries including over one-half of the 35 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2005. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt

Practices Act (the “FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. In addition, U.S. government agencies and authorities are conducting investigations into allegations of potential violations of laws.

We anticipate that the devotion of significant resources to compliance related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. Compliance related issues could limit our ability to do business in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with laws and regulations and our Business Code of Conduct. In the third quarter of 2005, our independent foreign subsidiaries initiated a process to prohibit any business activity that directly or indirectly involves or facilitates transactions in Iran, Sudan or with their governments, including government-controlled companies operating outside of these countries. Implementation of this process should be substantially complete by the end of 2006 and is not expected to have a material impact on our consolidated financial statements.

Risk Factors Related to Our Business

For discussion of our risk factors and cautions regarding forward-looking statements, see the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section, both contained herein. This list of risk factors is not intended to be all inclusive.

CRITICAL ACCOUNTING ESTIMATES

The preparation of our consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures and about contingent assets and liabilities. We base these estimates and judgments on historical experience and other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty, and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.

We have defined a critical accounting estimate as one that is both important to the portrayal of either our financial condition or results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We have discussed the development and selection of our critical accounting estimates with the Audit/Ethics Committee of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented below. During the past three fiscal years, we have not made any material changes in the methodology used to establish the critical accounting estimates discussed below. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation but are not deemed critical as defined above.

Allowance for Doubtful Accounts

The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2005 and 2004, allowance for doubtful accounts totaled $51.4 million, or 3.0%, and $50.2 million, or 3.6%, of total gross accounts receivable, respectively. We believe that our allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had a pre–tax impact of approximately $2.6 million in 2005.

Inventory Reserves

Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential outcomes. At December 31, 2005 and 2004, inventory reserves totaled $201.3 million, or 15.2%, and $220.0 million, or 17.7%, of gross inventory, respectively. We believe that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had a pre–tax impact of approximately $10.1 million in 2005.

Impairment of Long–Lived Assets

Long–lived assets, which include property, goodwill, intangible assets, investments in affiliates and certain other assets, comprise a significant amount of our total assets. We review the carrying values of these assets for impairment periodically, and at least annually for goodwill, or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long–term forecasts of future revenues and costs related to the assets subject to review. In turn, these forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions; however, based upon our evaluation of the current business climate in which we operate, we do not currently anticipate that any significant asset impairment losses will be necessary in the foreseeable future.

Income Taxes

The liability method is used for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.

We operate in more than 90 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

Our tax filings for various periods are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors that are difficult to estimate. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to

either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued. Although we have provided for the taxes that we believe will ultimately be payable as a result of these assessments, the aggregate assessments are approximately $34.1 million in excess of the taxes provided for in our consolidated financial statements.

In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we consider it probable that the taxes ultimately payable will exceed those amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in Statement of Financial Accounting Standards (“SFAS”) No. 5,Accounting for Contingencies. Future events such as changes in the facts or tax law, judicial decisions regarding existing law or a favorable audit outcome may later indicate the assertion of additional taxes is no longer probable. In that circumstance, it is possible that taxes previously provided would be released.

Pensions and Postretirement Benefit Obligations

Pensions and postretirement benefit obligations and the related plan expenses are calculated using actuarial models and methods. This involves the use of two critical assumptions, the discount rate and the expected rate of return on assets, both of which are important elements in determining plan expenses and in measuring plan assets and liabilities. We evaluate these critical assumptions at least annually. Although considered less critical, other assumptions used in determining benefit obligations and plan expenses, such as demographic factors like retirement age, mortality and turnover, are also evaluated periodically and are updated to reflect our actual and expected experience.

The discount rate enables us to state expected future cash flows at a present value on the measurement date. A lower discount rate increases the present value of benefit obligations and increases plan expenses. We used a discount rate of 6.00% in 2005, 6.25% in 2004 and 6.75% in 2003 to determine plan expenses. A 50 basis point reduction in the discount rate would have increased plan expenses in 2005 by $3.4 million.

To determine the expected rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets. A lower rate of return increases plan expenses. We assumed rates of return on our plan investments were 8.50% in 2005, 2004 and 2003. A 50 basis point reduction in the expected rate of return on assets of our principal plans would have increased plan expenses in 2005 by $2.9 million.

DISCONTINUED OPERATIONS

In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“SPD”), a product line group within the Completion and Production segment. SPD distributes basic supplies, products and small tools to the drilling industry. In January 2006, we signed a non–binding letter of intent for the sale of SPD. The sale is expected to close in the first quarter of 2006. SPD had revenues of $32.5 million for the year ended December 31, 2005. This transaction is subject to the negotiation and execution of a definitive sale agreement, as well as, various conditions, including satisfactory due diligence review of SPD’s business. There can be no assurance that the transaction will be consummated.

In September 2004, we completed the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within the Drilling and Evaluation segment that manufactured rotary drill bits used in the mining industry, for $31.5 million. We recorded a gain on the sale of $0.2 million, net of tax of $3.6 million, which consisted of a gain on the disposal of $6.8 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings.

In October 2003, we signed a definitive agreement for the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and recorded charges totaling $37.4 million, net of tax of $10.9 million, which consisted of a loss of $13.5 million on the write–down of BIRD to fair value, $6.2 million of severance and warranty accruals and a loss of $17.7 million related to the recognition of cumulative foreign currency translation adjustments into earnings. In January 2004, we completed the sale of BIRD and recorded an additional loss on the sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments. The adjustments were the result of changes in the value of assets sold to and liabilities assumed by the buyer between the date the initial sales price was negotiated and the closing of the sale.

In December 2002, we entered into exclusive negotiations for the sale of our interest in our oil producing operations in West Africa and received $10.0 million as a deposit. The transaction was effective as of January 1, 2003, and resulted in a gain on the sale of $4.1 million, net of a tax benefit of $0.2 million. We received the remaining $22.0 million in proceeds in April 2003.

In 2003, all purchase price adjustments related to the sale of EIMCO Process Equipment (“EIMCO”) were completed, resulting in the release of the escrow balance, of which we received $2.0 million and $2.9 million was returned to the buyer. We recorded an additional loss on the sale of EIMCO of $2.5 million, net of tax of $1.3 million.

We have reclassified the consolidated financial statements for all prior periods presented to reflect these operations as discontinued. See Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding discontinued operations.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our consolidated statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. The discussions are based on our consolidated financial results, as individual segments do not contribute disproportionately to our revenues, profitability or cash requirements.

The table below details certain consolidated statement of operations data and their percentage of revenues for 2005, 2004 and 2003, respectively (dollar amounts in millions).


	2005					2004					2003
	$		%			$		%			$		%

Revenues	$	7,185.5		100.0	%	$	6,079.6		100.0	%	$	5,233.3		100.0	%
Cost of revenues		4,942.5		68.8	%		4,351.0		71.6	%		3,807.5		72.8	%
Selling, general and administrative		1,009.6		14.1	%		912.2		15.0	%		824.6		15.8	%

Revenues

Revenues for 2005 increased 18.2% compared with 2004, primarily due to increases in activity, as evidenced by a 14.8% increase in the worldwide rig count, pricing improvements of between four and six percent and increases in market share in selected product lines and geographic areas. These increases were partially offset by the impact of hurricanes in the Gulf of Mexico. Revenues in North America, which accounted for 42.4% of total revenues, increased 20.9% for 2005 compared with 2004, despite the unfavorable impact on our U.S. offshore revenues of approximately $68.0 million from hurricane–related disruptions. This increase reflects increased activity in the U.S., as evidenced by the 18.0% increase in the North American rig count, with activity dominated by land–based gas–directed drilling. Revenues outside North America, which accounted for 57.6% of total revenues, increased 16.3% for 2005 compared with 2004. This increase reflects the improvement in international drilling activity, as evidenced by the 8.6% increase in the rig count outside North America, particularly in Latin America, the Middle East and Asia Pacific, coupled with price increases in certain markets and product lines.

Revenues for 2004 increased 16.2% compared with 2003, reflecting a 10.1% increase in the worldwide rig count. Revenues in North America, which accounted for 41.5% of total revenues, increased 14.4% compared with 2003. This increase reflects increased drilling activity in the U.S. and Canada, as evidenced by a 10.9% increase in the North American rig count, and $24.8 million related to intellectual property license fees, which is not expected to recur in the same magnitude in the future. Revenues outside North America, which accounted for 58.5% of total revenues, increased 17.5% compared with 2003. This increase reflects the improvement in international drilling activity, as evidenced by an 8.6% increase in the rig count outside North America, primarily in Latin America and Asia Pacific, partially offset by decreased drilling activity in the North Sea and Africa. During 2004, our revenue growth was primarily due to increases in activity and, to a lesser extent, pricing improvements.

Cost of Revenues

Cost of revenues for 2005 increased 13.6% compared with 2004. Cost of revenues as a percentage of revenues was 68.8% and 71.6% for 2005 and 2004, respectively. The decrease in cost of revenues as a percentage of revenue is primarily the result of overall price increases of between four and six percent and very high utilization of our rental tool fleet and personnel. These increases were partially offset by higher raw material costs and employee compensation expenses.

Cost of revenues for 2004 increased 14.3% compared with 2003. Cost of revenues as a percentage of revenues was 71.6% and 72.8% for 2004 and 2003, respectively. The decrease in cost of revenues as a percentage of revenues is primarily related to limited pricing improvement in certain markets and product lines and improved cost control measures, including lower repair and maintenance costs at our INTEQ division, partially offset by increased material costs and higher employee compensation expense. A change in the geographic and product mix from the sale of our products and services also contributed to the decrease in the cost of revenues as a percentage of revenues. During 2004, our revenue increases came predominantly from outside North America and our margins on revenues generated outside North America are typically higher than margins generated in North America.

Selling, General and Administrative

Selling, general and administrative (“SG&A”) expenses increased 10.7% in 2005 compared with 2004. The increase corresponds with increased activity and resulted primarily from higher marketing and employee compensation expenses.

SG&A expenses for 2004 increased 10.6% compared with 2003. This increase was primarily due to higher marketing and administrative expenses as a result of increased activity, including higher employee compensation expense, and increased costs related to our continued focus on compliance, including legal investigations and increased staffing in our legal, compliance and audit groups. The increase was also due to the implementation of programs and procedures as a result of the requirements of the Sarbanes–Oxley Act of 2002.

Reversal of Restructuring Charge

In 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and we recorded a restructuring charge of $29.5 million. Included in the restructuring charge was $1.1 million for a contractual obligation related to an oil and natural gas property in Angola. The property was subsequently sold in 2003, and we reversed the liability related to this contractual obligation, accordingly.

Impairment of Investment in Affiliate

In 2003, as a result of the continued weakness in the seismic industry, we evaluated the carrying value of our investment in WesternGeco and recorded an impairment loss of $45.3 million to write–down the investment to its fair value. The fair value was determined using a combination of a market capitalization and discounted cash flow approach. We were assisted in the determination of the fair value by a third party. Although not anticipated, further declines in the fair value of the investment in WesternGeco would result in additional impairments.

Equity in Income (Loss) of Affiliates

Equity in income of affiliates increased $63.8 million in 2005 compared with 2004. The increase is almost entirely due to the increase in equity in income of WesternGeco, our most significant equity method investment. WesternGeco’s revenue and profitability has continued to improve as a result of ongoing favorable market conditions in the seismic industry.

Equity in income of affiliates was $36.3 million in 2004 compared with equity in loss of affiliates of $2.1 million in 2003, which excludes the $135.7 million related to our portion of the restructuring and impairment charge taken by WesternGeco in the third quarter of 2003. During 2003, the operating results of WesternGeco continued to be adversely affected by the weakness in the seismic industry and, as a result of this weakness, WesternGeco recorded certain impairment and restructuring charges of $452.0 million for impairment of its multiclient seismic library and rationalization of its marine seismic fleet.

Interest Expense and Interest Income

Interest expense decreased $11.3 million in 2005 compared with 2004. The decrease was primarily due to lower total debt levels partially offset by the impact of the interest rate swap agreement that was in place from April 2004 through June 2005. The lower total debt levels were a result of the repayment of $350.0 million of long–term debt in the second quarter of 2004. Interest income in 2005 increased $11.2 million over 2004, due to significantly higher cash balances and short–term investments during the year resulting primarily from higher cash flows from operations.

Interest expense for 2004 decreased $19.5 million compared with 2003, primarily due to lower total debt levels and the effect of the interest rate swap agreement entered into in April 2004. The lower total debt levels are the result of the repayment of $350.0 million of long–term debt in the second quarter of 2004, which decreased interest expense by $16.0 million in 2004 compared with 2003. Additionally, the favorable impact of the interest rate swap agreement decreased interest expense by $4.1 million in 2004 compared with 2003.

Income Taxes

Our effective tax rates differ from the U.S. statutory income tax rate of 35% due to state income taxes, differing rates of tax on international operations and higher taxes within the WesternGeco venture. Additionally, in 2005 we have reflected a $10.6 million reduction to tax expense attributable to the recognition of a deferred tax asset associated with our supplemental retirement plan (“SRP”).

During 2003, we recognized an incremental effect of $36.3 million of additional taxes attributable to our portion of the operations of WesternGeco. Of this amount, $15.9 million related to the reduction in the carrying value of our equity investment in WesternGeco for which there was no tax benefit. The remaining $20.4 million arose from operations of the venture due to: (i) the venture being taxed in certain foreign jurisdictions based on a deemed profit basis, which is a percentage of revenues rather than profits and (ii) unbenefitted foreign losses of the venture, which are operating losses and impairment and restructuring charges in certain foreign jurisdictions where there was no current tax benefit and where a deferred tax asset was not recorded due to the uncertainty of realization.

During 2005 and 2003, benefits of $4.3 million and $3.3 million, respectively, were recognized as the result of various refund claims filed in the U.S.

Our tax filings for various periods are subjected to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

Cumulative Effect of Accounting Change

On December 31, 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47 (“FIN 47”),Conditional Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations,refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with the special handling of asbestos related materials in certain facilities. We also have certain facilities that contain asbestos related materials for which a liability has not been recognized because the fair value cannot be reasonably estimated. We believe that there are indeterminate settlement dates for these obligations because the range of time over which we would settle these obligations is unknown or cannot be estimated; therefore, sufficient information does not exist to apply an expected present value technique.

On January 1, 2003, we adopted SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate can be made. The liability for the ARO is revised each subsequent period due to the passage of time and changes in estimates. The associated retirement costs are capitalized as part of the carrying amount of the long–lived asset and subsequently depreciated over the estimated useful life of the asset. The adoption of SFAS No. 143 in 2003 resulted in a charge of $5.6 million, net of tax of $2.8 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded ARO liabilities of $11.4 million primarily for anticipated costs of obligations associated with the future disposal of power source units at certain of our divisions and refurbishment costs associated with certain leased facilities in Europe and with a fleet of leased railcars and tanks.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During 2005, cash flows from operations and proceeds from the issuance of common stock resulting from the exercise of stock options were the principal sources of funding. We anticipate that cash flows from operations will be sufficient to fund our liquidity needs in 2006. We also have a $500.0 million committed revolving credit facility that provides back–up liquidity in the event an unanticipated and significant demand on cash flows could not be funded by operations.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In 2005, we used cash for a variety of activities including working capital needs, payment of dividends, repurchase of common stock, repayments of borrowings and capital expenditures.

Cash Flows

Cash flows provided (used) by continuing operations by type of activity were as follows for the years ended December 31 (in millions):


	2005			2004			2003

Operating activities	$	949.6		$	781.8		$	649.0
Investing activities		(465.3	)		(196.3	)		(360.7	)
Financing activities		(108.1	)		(352.2	)		(335.8	)

Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given year, as these are noncash changes. As a result, changes reflected in certain accounts on the consolidated statements of cash flows may not reflect the changes in corresponding accounts on the consolidated balance sheets.

Operating Activities

Cash flows from operating activities have been steadily increasing over the last three years and we expect this trend to continue in 2006. We attribute the increases in our cash flow to the increasing levels of income from continuing operations adjusted for noncash items.

Cash flows from operating activities of continuing operations increased $167.8 million in 2005 compared with 2004. This increase was primarily due to an increase in income from continuing operations of $349.1 million partially offset by a change in net operating assets and liabilities that used $180.6 million more in cash flows during 2005 compared with 2004.

The underlying drivers of the changes in operating assets and liabilities are as follows:

	•		An increase in accounts receivable used $329.4 million in cash in 2005 compared with using $173.7 million in cash in 2004. This was due to the increase in revenues and an increase in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately three days.

	•		A build up in inventory in anticipation of and related to increased activity used $108.7 million in cash in 2005 compared with using $3.2 million in cash in 2004.

	•		An increase in accounts payable, accrued employee compensation and other accrued liabilities provided $269.6 million in cash in 2005 compared with providing $189.0 million in cash in 2004. This was due primarily to increased activity and increased employee compensation accruals.

Our contributions to our defined benefit pension plans in 2005 were approximately $48.0 million, a decrease of approximately $62.0 million compared to 2004, due to higher funding in excess of the minimum requirements in 2004.

Cash flows from operating activities of continuing operations increased $132.8 million in 2004 compared with 2003. The increase was primarily due to increased operating performance attributable to our increased revenues. In addition, changes in net operating assets and liabilities provided $11.1 million less in cash flows during 2004 compared with 2003.

The underlying drivers of the changes in operating assets and liabilities are as follows:

	•		An increase in accounts receivable used $173.7 million in cash in 2004 compared with using $13.8 million in cash in 2003. This was due to the increase in revenues and an increase in days sales outstanding of approximately two days.

	•		A build up in inventory in anticipation of increased activity used $3.2 million in cash in 2004 compared with providing $20.7 million in cash in 2003. The build up in inventory was partially offset by our continued focus on improving the utilization of inventory on hand.

•

An increase in accounts payable, accrued employee compensation and other accrued liabilities provided $189.0 million in cash in 2004 compared with providing $16.3 million in cash in 2003. This was due primarily to increased activity and increased employee compensation accruals.

Our contributions to our defined benefit pension plans in 2004 were approximately $110.0 million, an increase of approximately $82.0 million compared with 2003, due to our decision to improve the funded status of certain pension plans and to provide us with increased flexibility on the future funding of these pension plans.

Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools in place to generate revenues from operations. Expenditures for capital assets totaled $478.3 million, $348.2 million and $403.9 million for 2005, 2004 and 2003, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline tools and equipment.

During 2005, we paid $46.8 million for acquisitions of businesses, net of cash acquired. In December, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million. In November, we paid $25.5 million, net of cash acquired of $1.7 million, for the remaining 50% interest in QuantX Wellbore Instrumentation (“QuantX”), a venture we entered into in 2003 which is engaged in the permanent in–well monitoring market. During 2005, we also made smaller acquisitions having an aggregate purchase price of $1.0 million.

During 2005, we purchased $77.0 million of auction rate securities, which are highly liquid, variable–rate debt securities. While the underlying security has a long–term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days, creating short–term liquidity. These short–term investments are classified as available–for–sale and are recorded at cost, which approximates market value.

Proceeds from disposal of assets were $90.1 million, $106.9 million and $66.8 million for 2005, 2004 and 2003, respectively. These disposals relate to rental tools that were lost–in–hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the year. Included in the proceeds for 2004 was $12.2 million related to the sale of certain real estate properties held for sale.

In 2005, we received distributions of $30.0 million from WesternGeco, which were recorded as a reduction in the carrying value of our investment. We also received $13.3 million from Schlumberger related to the WesternGeco true–up payment, of which $13.0 million was recorded as a reduction in the carrying value of our investment and $0.3 million as interest income.

In May 2005, we received $3.7 million from the release of a portion of the amount held in escrow related to our sale of Petreco International. The remainder is expected to be released to us in the first quarter of 2006, subject to the indemnity obligations under the sales agreement.

In 2004, we paid $6.6 million for acquisition of businesses, net of cash acquired. We purchased the remaining 60% interest in Luna Energy L.L.C. (“Luna”), a venture we entered into in 2002, for $1.0 million. We also paid $5.6 million in settlement of the final purchase price related to an acquisition completed in a prior year and invested an additional $7.1 million in certain of our investments in affiliates.

In 2003, we made two acquisitions having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. In addition, during 2003, we invested $38.1 million in affiliates, of which $30.1 million related to our 50% interest in QuantX.

In 2004, we received $58.7 million in net proceeds from the sale of businesses and our interest in an affiliate. In January, we completed the sale of BIRD and received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price. In June 2004, we made a net payment of $6.8 million to the buyer of BIRD in settlement of the final purchase price adjustments. In February 2004, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, and received proceeds of $35.8 million, of which $7.4 million was placed in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. In September, we also completed the sale of BHMT and received proceeds of $31.5 million.

In 2003, we received $24.0 million in net proceeds from the sale of businesses. In April, we completed the sale of our interest in an oil producing property in West Africa and received the remaining $22.0 million in proceeds. We also completed all purchase price adjustments related to the sale of our EIMCO division and received $2.0 million from the release of the escrow balance.

We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. We may also from time to time sell business operations that are not considered part of our core business.

Financing Activities

We had net (repayments) borrowings of commercial paper and other short–term debt of $(71.1) million, $35.5 million and $11.2 million in 2005, 2004 and 2003, respectively. In 2004, we repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. In 2003, we repaid the $100.0 million 5.8% Notes due February 2003. These repayments were funded with cash on hand, cash flows from operations and the issuance of commercial paper.

Total debt outstanding at December 31, 2005 was $1,087.9 million, a decrease of $74.4 million compared with December 31, 2004. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.19 at December 31, 2005 and 0.23 at December 31, 2004.

In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. The interest rate swap agreement was designated and qualified as a fair value hedging instrument. Due to our outlook for interest rates, we terminated the interest rate swap agreement in June 2005, which required us to make a payment of $5.5 million. This amount was deferred and is being amortized as an increase to interest expense over the remaining life of the underlying debt security.

At different times during 2003, we entered into three separate interest rate swap agreements, each for a notional amount of $325.0 million, associated with our 6.25% Notes due January 2009. These agreements had been designated and had qualified as fair value hedging instruments. Due to our outlook for interest rates, we terminated the three agreements and received payments totaling $26.9 million. Each of the three agreements was terminated prior to entering into a new agreement. The deferred gains are being amortized as a reduction of interest expense over the remaining life of the underlying debt security.

We received proceeds of $228.1 million, $115.9 million and $61.8 million in 2005, 2004 and 2003, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

On October 27, 2005, the Board of Directors authorized us to repurchase up to $455.5 million of common stock, which was in addition to the balance of $44.5 million remaining from the Board of Directors’ September 2002 authorization, resulting in the authorization to repurchase up to a total of $500.0 million of common stock. On November 3, 2005, we entered into a Stock Purchase Plan with an agent for the purchase of shares of our common stock that complies with the requirements of Rule 10b5–1 promulgated by the Securities Exchange Act of 1934. The term of the November Plan will run from November 7, 2005 until April 30, 2006, unless earlier terminated. On February 22, 2006, we entered into another Plan for a term that will run from February 23, 2006 until April 30, 2006, unless earlier terminated. During that term, the agent will use its best efforts to repurchase a fixed dollar value of our common stock each trading day, subject to applicable trading rules, until the cumulative amount purchased under the November Plan equals $250.0 million and under the February Plan equals $150.0 million, inclusive of all commissions and fees paid by us to the agent related to such repurchases. Shares will be repurchased by the agent at the prevailing market prices, subject to limitations provided by us, in open market transactions intended to comply with Rule 10b–18 of the Exchange Act. We or the agent may terminate the Plans. However, no shares will be repurchased at any time that the cost of the shares exceeds an amount that has been specified by us to the agent. During the fourth quarter of 2005, we repurchased 1.7 million shares of our common stock at an average price of $58.17 per share, for a total of $98.5 million. During 2003, we repurchased 6.3 million shares at an average price of $28.78 per share, for a total of $181.4 million. Upon repurchase, the shares were retired.

We paid dividends of $161.1 million, $153.6 million and $154.3 million in 2005, 2004 and 2003, respectively. Beginning in the fourth quarter of 2005 as authorized by our Board of Directors, we increased our quarterly dividend to $0.13 per share, compared to $0.115 per share that was paid in prior quarters.

Available Credit Facilities

At December 31, 2005, we had $955.6 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2010. The facility provides for up to three one–year extensions, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility) of less than or equal to 0.60, restrict certain merger transactions or the sale

of all or substantially all of the assets of the company or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At December 31, 2005, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the year ended December 31, 2005; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2005, we had no outstanding commercial paper.

If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. We do not have any ratings triggers in the facility that would accelerate the maturity of any borrowings under the facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

We believe our credit ratings and relationships with major commercial and investment banks would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long–term debt or equity, if necessary.

Cash Requirements

In 2006, we believe operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short–term and long–term operating strategies.

We currently expect 2006 capital expenditures will be between $750.0 million and $780.0 million, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations.

In 2006, we expect to make interest payments of between $72.0 million and $77.0 million. This is based on our current expectations of debt levels during 2006. We also expect to make income tax payments of between $490.0 million and $530.0 million in 2006.

As of December 31, 2005, we have authorization remaining to repurchase up to $401.5 million in common stock. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $170.0 million and $180.0 million in 2006; however, the Board of Directors can change the dividend policy at anytime.

During 2006, we estimate we will contribute between $18.0 million and $23.0 million to our defined benefit pension plans and make benefit payments related to postretirement welfare plans of between $15.0 million and $17.0 million. We also estimate we will contribute between $85.0 million and $95.0 million to our defined contribution plans.

We do not believe there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than previously discussed, we currently have no information that would create a reasonable likelihood that the reported levels of revenues and cash flows from operations in 2005 are not indicative of what we can expect in the future.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2005. Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.


	Payments Due by Period (In millions)
			Less Than		1 – 3		4 – 5		More than
	Total		1 year		Years		Years		5 Years

Total debt⁽¹⁾	$	1,084.9	$	9.9	$	—	$	525.0	$	550.0
Estimated interest payments⁽²⁾		996.5		72.6		145.2		96.8		681.9
Operating leases⁽³⁾		314.0		74.7		93.8		41.8		103.7
Purchase obligations⁽⁴⁾		173.0		163.2		9.8		—		—
Other long–term liabilities⁽⁵⁾		52.4		12.8		20.7		6.0		12.9

Total	$	2,620.8	$	333.2	$	269.5	$	669.6	$	1,348.5


⁽¹⁾		Amounts represent the expected cash payments for our total debt and do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements.

⁽²⁾		Amounts represent the expected cash payments for interest on our fixed rate long–term debt.

⁽³⁾		We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the lease. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.

⁽⁴⁾		Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable at anytime without penalty.

⁽⁵⁾		Amounts represent other long–term liabilities, including the current portion, reflected in the consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions, payments for various postretirement welfare benefit plans and postemployment benefit plans and payments for deferred taxes and other tax liabilities.

Off–Balance Sheet Arrangements

In the normal course of business with customers, vendors and others, we have entered into off–balance sheet arrangements, such as letters of credit and other bank issued guarantees, which totaled approximately $319.8 million at December 31, 2005. In addition, at December 31, 2005, we have guaranteed debt and other obligations of third parties with a maximum potential exposure of $1.4 million. None of these off–balance sheet arrangements either has, or is likely to have, a material effect on our current or future financial condition, results of operations, liquidity or capital resources.

Other than normal operating leases, we do not have any off–balance sheet financing arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or special purpose entities. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

NEW ACCOUNTING STANDARDS

In November 2004, the FASB issued SFAS No. 151,Inventory Costs — an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We adopted SFAS No. 151 on January 1, 2006, with no material effect on our consolidated financial statements.

In December 2004, the FASB issued the revised SFAS No. 123,Share–Based Payment(“SFAS No. 123(R)”). SFAS No. 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) requires an entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant–date fair value of the award. That cost will be recognized over the period in which an employee is required to provide service in exchange for the award. SFAS No. 123(R) also requires an entity to initially measure the cost of employee services rendered in exchange for an award of liability instruments at its current fair value. The fair value of that award is to be remeasured subsequently at each reporting date through the settlement date. Changes in the fair value during the required service period are to be recognized as compensation cost over that period. In accordance with guidance issued by the SEC that delayed the effective date of SFAS No. 123(R), we adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective method, whereby we will recognize expense on any previously granted unvested awards over the remaining service period of the award. New awards granted after the adoption date will be expensed over the estimated service period. Based on our current estimates, we expect the impact in 2006 of the adoption of SFAS No. 123(R) to be additional expense of between $18.0 million and $20.0 million, net of tax. We are continuing to evaluate the various option pricing models and the required assumptions and estimates that will be used in determining the fair value of awards made in 2006. In addition, we have estimated the number of awards to be granted in 2006 because the final amount has not been determined. As a result, the actual amount recorded as expense in 2006 may be different from this estimated amount and this estimated amount may not be indicative of the expense we may incur in future years.

In December 2004, the FASB issued FASB Staff Position No. 109–1 (“FSP 109–1”),Application of FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which provides guidance on the American Jobs Creation Act of 2004 (the “Act”). The Act provides a tax deduction for income from qualified domestic production activities. FSP 109–1 provides for the treatment of the deduction as a special deduction as described in SFAS No. 109. As such, the deduction will have no effect on existing deferred tax assets and liabilities. The impact of the deduction is to be reported in the period in which the deduction is claimed on our U.S. tax return. We adopted FSP 109–1 on January 1, 2005, with no material impact on our 2005 effective tax rate, and we do not expect that this deduction will have a material impact on our effective tax rate in future years.

In December 2004, the FASB issued FASB Staff Position No. 109–2 (“FSP 109–2”),Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004,which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109–2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have decided not to elect to repatriate foreign earnings under the provisions in the Act. Accordingly, our consolidated financial statements do not reflect a provision for taxes related to this election.

In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We adopted FIN 47 on December 31, 2005, which resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with certain conditional asset retirement obligations.

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20 (“APB No. 20”),Accounting Changes, and SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period–specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006.

RELATED PARTY TRANSACTIONS

In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true–up payment was to be made by either of the parties based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic data libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party would be required to make as a result of this adjustment was $100.0 million. In August 2005, we received $13.3 million from Schlumberger related to

the true–up payment. We recorded $13.0 million as a reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest income. The income tax effect of $3.3 million related to this payment is included in our provision for income taxes for the year ended December 31, 2005.

In November 2000, we also entered into an agreement with WesternGeco whereby WesternGeco subleased a facility from us for a period of ten years at then current market rates. During 2005, 2004 and 2003, we received payments of $6.5 million, $5.5 million and $5.0 million, respectively, from WesternGeco related to this lease.

During 2005, we received distributions of $30.0 million from WesternGeco, which were recorded as reductions in the carrying value of our investment.

Effective December 1, 2005, either party to the WesternGeco Master Formation Agreement may offer to sell its entire interest in the venture to the other party at a cash purchase price per percentage interest specified in an offer notice. If the offer to sell is not accepted, the offering party will be obligated to purchase and the other party will be obligated to sell its entire interest at the same price per percentage interest as the price specified in the offer notice.

At December 31, 2005 and 2004, net accounts receivable (payable) from unconsolidated affiliates totaled $0.4 million and $(1.1) million, respectively. There were no other significant related party transactions.

FORWARD–LOOKING STATEMENTS

MD&A and certain statements in the Notes to Consolidated Financial Statements include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward–looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. Our forward–looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward–looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of our common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Risk Factors Related to Our Business” sections contained in Item 1A. Risk Factors and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”). These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) at http://www.sec.gov.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks that are inherent in our financial instruments and arise in the normal course of business. We may enter into derivative financial instrument transactions to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative purposes. A discussion of our primary market risk exposure in financial instruments is presented below.

INDEBTEDNESS

We are subject to interest rate risk on our long–term fixed interest rate debt. Commercial paper borrowings, other short–term borrowings and variable rate long–term debt do not give rise to significant interest rate risk because these borrowings either have maturities of less than three months or have variable interest rates. All other things being equal, the fair market value of debt with a fixed interest rate will increase as interest rates fall and will decrease as interest rates rise. This exposure to interest rate risk is managed by borrowing money that has a variable interest rate or using interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.

At December 31, 2005 and 2004, we had fixed rate debt aggregating $1,075.0 million and $1,075.2 million, respectively. The following table sets forth the required cash payments for our indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the related weighted average effective interest rates by expected maturity dates as of December 31, 2005 and 2004 (dollar amounts in millions).


	2005			2006			2007		2008		2009			2010		Thereafter			Total
As of December 31, 2005:
Long–term debt^{(1) (2)}	$	—		$	—		$	—	$	—	$	525.0		$	—	$	550.0		$	1,075.0
Weighted average effective interest rates												5.19	%⁽³⁾				7.55	%		6.37	%⁽³⁾

As of December 31, 2004:
Long–term debt^{(1) (2)}	$	0.1		$	0.1		$	—	$	—	$	525.0		$	—	$	550.0		$	1,075.2
Weighted average effective interest rates		12.30	%		6.50	%						4.96	%⁽³⁾⁽⁴⁾				7.55	%		6.24	%⁽³⁾⁽⁴⁾

Fixed to variable swaps⁽⁴⁾
Notional amount											$	325.0							$	325.0
Pay rate												4.60	%⁽⁵⁾							4.60	%⁽⁵⁾
Receive rate												6.25	%							6.25	%


⁽¹⁾		Amounts do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements.

⁽²⁾		Fair market value of fixed rate long–term debt was $1,223.7 million at December 31, 2005 and $1,239.0 million at December 31, 2004.

⁽³⁾		Includes the effect of the amortization of net deferred gains on terminated interest rate swap agreements.

⁽⁴⁾		Includes the fair market value of the interest rate swap agreement entered into in April 2004. The fair market value of the interest rate swap agreement was a $2.3 million liability at December 31, 2004.

⁽⁵⁾		Six–month LIBOR for the U.S. Dollar, reset semi–annually in January and July, plus 2.741%.

INTEREST RATE SWAP AGREEMENTS

At December 31, 2005, there were no interest rate swap agreements in effect. Due to our outlook for interest rates, on June 2, 2005, we terminated the interest rate swap agreement we had entered into in April 2004. This agreement had been designated and had qualified as a fair value hedging instrument. Upon termination we were required to pay $5.5 million. This amount is being amortized as an increase to interest expense over the remaining life of the underlying debt security, which matures in January 2009.

In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. Under the agreement we received interest at a fixed rate of 6.25% and paid interest at a floating rate of six–month LIBOR plus a spread of 2.741%. The interest rate swap agreement was designated and qualified as a fair value hedging instrument. The interest rate swap agreement was fully effective, resulting in no gain or loss recorded in the consolidated statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $2.3 million liability at December 31, 2004, based on quoted market prices for contracts with similar terms and maturity dates.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

We conduct operations around the world in a number of different currencies. Many of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to fluctuations in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

instruments. Based on quoted market prices as of December 31, 2005 for contracts with similar terms and maturity dates, we recorded a gain of $0.1 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

At December 31, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including the British Pound Sterling, the Norwegian Krone, the Euro and the Brazilian Real. These contracts were designated and qualified as fair value hedging instruments. Based on quoted market prices as of December 31, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $0.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

At December 31, 2004, we had also entered into several foreign currency forward contracts with notional amounts aggregating $122.4 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. The funding of such imbalances was supported by short–term intercompany borrowing commitments that had definitive amounts and funding dates. All funding took place before December 31, 2005. These foreign currency forward contracts were designated as cash flow hedging instruments and were fully effective. Based on quoted market prices as of December 31, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $0.1 million to adjust these foreign currency forward contracts to their fair market value. The loss was recorded in other comprehensive income in the consolidated balance sheet.

The counterparties to the forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as such term is defined in Exchange Act Rules 13a–15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our control environment is the foundation for our system of internal control and is embodied in our Business Code of Conduct, which sets the tone of our company and includes our Core Values of Integrity, Teamwork, Performance and Learning. Included in our system of internal control are written policies, an organizational structure providing division of responsibilities, the selection and training of qualified personnel and a program of financial and operations reviews by a professional staff of internal auditors. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting. Our evaluation was based on the framework inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our evaluation under the framework inInternal Control — Integrated Framework, our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2005. The conclusion of our principal executive officer and principal financial officer is based on the recognition that there are inherent limitations in all systems of internal control. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.


/s/ CHAD C. DEATON	/s/ G. STEPHEN FINLEY	/s/ ALAN J. KEIFER
Chad C. Deaton	G. Stephen Finley	Alan J. Keifer
Chairman and	Senior Vice President —	Vice President and
Chief Executive Officer	Finance and Administration	Controller
	and Chief Financial Officer

Houston, Texas
February 23, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Baker Hughes Incorporated and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule II as of and for the year ended December 31, 2005 of the Company; and our report dated February 23, 2006, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 23, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas

We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule II, valuation and qualifying accounts listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Baker Hughes Incorporated and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 23, 2006

Baker Hughes Incorporated
Consolidated Statements of Operations
(In millions, except per share amounts)


	Year Ended December 31,
	2005			2004			2003

Revenues	$	7,185.5		$	6,079.6		$	5,233.3


Costs and expenses:
Cost of revenues		4,942.5			4,351.0			3,807.5
Selling, general and administrative		1,009.6			912.2			824.6
Impairment of investment in affiliate		—			—			45.3
Reversal of restructuring charge		—			—			(1.1	)

Total costs and expenses		5,952.1			5,263.2			4,676.3


Operating income		1,233.4			816.4			557.0
Equity in income (loss) of affiliates		100.1			36.3			(137.8	)
Interest expense		(72.3	)		(83.6	)		(103.1	)
Interest income		18.0			6.8			5.3


Income from continuing operations before income taxes		1,279.2			775.9			321.4
Income taxes		(404.8	)		(250.6	)		(145.6	)


Income from continuing operations		874.4			525.3			175.8
Income (loss) from discontinued operations, net of tax		4.9			3.3			(41.3	)

Income before cumulative effect of accounting change		879.3			528.6			134.5
Cumulative effect of accounting change, net of tax		(0.9	)		—			(5.6	)

Net income	$	878.4		$	528.6		$	128.9


Basic earnings per share:
Income from continuing operations	$	2.58		$	1.57		$	0.52
Income (loss) from discontinued operations		0.01			0.01			(0.12	)
Cumulative effect of accounting change		—			—			(0.02	)

Net income	$	2.59		$	1.58		$	0.38


Diluted earnings per share:
Income from continuing operations	$	2.56		$	1.57		$	0.52
Income (loss) from discontinued operations		0.01			0.01			(0.12	)
Cumulative effect of accounting change		—			—			(0.02	)

Net income	$	2.57		$	1.58		$	0.38

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except par value)


	December 31,
	2005			2004

ASSETS

Current Assets:
Cash and cash equivalents	$	697.0		$	319.0
Short–term investments		77.0			—
Accounts receivable — less allowance for doubtful accounts:
December 31, 2005, $51.4; December 31, 2004, $50.2		1,673.4			1,351.2
Inventories		1,126.3			1,025.3
Deferred income taxes		181.2			199.7
Other current assets		68.6			56.6
Assets of discontinued operations		16.6			16.7

Total current assets		3,840.1			2,968.5

Investments in affiliates		678.9			678.1
Property — less accumulated depreciation:
December 31, 2005, $2,475.7; December 31, 2004, $2,380.5		1,355.5			1,332.2
Goodwill		1,315.8			1,267.0
Intangible assets — less accumulated amortization:
December 31, 2005, $84.5; December 31, 2004, $70.2		163.4			155.1
Other assets		453.7			420.4

Total assets	$	7,807.4		$	6,821.3


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	558.1		$	452.1
Short–term borrowings and current portion of long–term debt		9.9			76.0
Accrued employee compensation		424.5			368.4
Income taxes		141.5			104.8
Other accrued liabilities		222.9			226.0
Liabilities of discontinued operations		3.8			2.9

Total current liabilities		1,360.7			1,230.2

Long–term debt		1,078.0			1,086.3
Deferred income taxes and other tax liabilities		228.1			231.9
Pensions and postretirement benefit obligations		336.1			308.3
Other liabilities		106.7			69.2
Commitments and contingencies

Stockholders’ Equity:
Common stock, one dollar par value (shares authorized — 750.0; outstanding — 341.5 at December 31, 2005 and 336.6 at December 31, 2004)		341.5			336.6
Capital in excess of par value		3,293.5			3,127.8
Retained earnings		1,263.2			545.9
Accumulated other comprehensive loss		(188.0	)		(109.8	)
Unearned compensation		(12.4	)		(5.1	)

Total stockholders’ equity		4,697.8			3,895.4

Total liabilities and stockholders’ equity	$	7,807.4		$	6,821.3

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Stockholders’ Equity
(In millions, except per share amounts)


				Capital						Accumulated
				in Excess						Other
	Common			of			Retained			Comprehensive			Unearned
	Stock			Par Value			Earnings			Loss			Compensation			Total

Balance, December 31, 2002	$	335.8		$	3,111.6		$	196.3		$	(246.5	)	$	—		$	3,397.2
Comprehensive income:
Net income								128.9
Foreign currency translation adjustments:
Reclassifications included in net income due to sale of business											17.7
Translation adjustments, net of tax of $0.3											95.6
Change in minimum pension liability, net of tax of $5.3											(17.9	)
Total comprehensive income																	224.3
Cash dividends ($0.46 per share)								(154.3	)								(154.3	)
Stock issued pursuant to employee stock plans, net of tax of $1.5		2.5			62.1												64.6
Repurchase and retirement of common stock		(6.3	)		(175.1	)											(181.4	)

Balance, December 31, 2003		332.0			2,998.6			170.9			(151.1	)		—			3,350.4
Comprehensive income:
Net income								528.6
Foreign currency translation adjustments:
Reclassifications included in net income due to sale of business											6.6
Translation adjustments, net of tax of $2.3											30.8
Change in minimum pension liability, net of tax of $(1.8)											4.0
Loss on derivative instruments, net of tax of $0.01											(0.1	)
Total comprehensive income																	569.9
Cash dividends ($0.46 per share)								(153.6	)								(153.6	)
Issuance of restricted stock, net of tax of $1.1		0.2			6.7									(5.6	)		1.3
Amortization of unearned compensation, net of tax of $(0.2)														0.5			0.5
Stock issued pursuant to employee stock plans, net of tax of $12.5		4.4			122.5												126.9

Balance, December 31, 2004		336.6			3,127.8			545.9			(109.8	)		(5.1	)	��	3,895.4
Comprehensive income:
Net income								878.4
Foreign currency translation adjustments, net of tax of $0.1											(65.0	)
Change in minimum pension liability, net of tax of $5.5											(12.2	)
Other											(1.0	)
Total comprehensive income																	800.2
Cash dividends ($0.475 per share)								(161.1	)								(161.1	)
Issuance of restricted stock net of cancellations, net of tax of $6.6		0.4			19.2									(12.3	)		7.3
Amortization of unearned compensation, net of tax of $(2.1)														5.0			5.0
Stock issued pursuant to employee stock plans, net of tax of $19.8		6.2			243.3												249.5
Repurchase and retirement of common stock		(1.7	)		(96.8	)											(98.5	)

Balance, December 31, 2005	$	341.5		$	3,293.5		$	1,263.2		$	(188.0	)	$	(12.4	)	$	4,697.8

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions)


	Year Ended December 31,
	2005			2004			2003

Cash flows from operating activities:
Income from continuing operations	$	874.4		$	525.3		$	175.8
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		382.4			371.6			347.3
Amortization of net deferred gains on derivatives		(5.7	)		(7.9	)		(6.7	)
Amortization of unearned compensation		7.1			0.7			—
Acquired in–process research and development		5.1			1.8			—
Provision (benefit) for deferred income taxes		7.4			48.4			(20.1	)
Gain on disposal of assets		(34.8	)		(37.8	)		(30.2	)
Impairment of investment in affiliate		—			—			45.3
Equity in (income) loss of affiliates		(100.1	)		(36.3	)		137.8
Changes in operating assets and liabilities:
Accounts receivable		(329.4	)		(173.7	)		(13.8	)
Inventories		(108.7	)		(3.2	)		20.7
Accounts payable		122.3			48.3			15.6
Accrued employee compensation and other accrued liabilities		147.3			140.7			0.7
Pensions and postretirement benefit obligations and other liabilities		41.7			(30.4	)		(23.0	)
Other		(59.4	)		(65.7	)		(0.4	)

Net cash flows from continuing operations		949.6			781.8			649.0
Net cash flows from discontinued operations		5.8			1.9			7.1

Net cash flows from operating activities		955.4			783.7			656.1


Cash flows from investing activities:
Expenditures for capital assets		(478.3	)		(348.2	)		(403.9	)
Acquisition of businesses, net of cash acquired		(46.8	)		(6.6	)		(9.5	)
Purchase of short–term investments		(77.0	)		—			—
Proceeds from disposal of assets		90.1			106.9			66.8
Distributions from WesternGeco		30.0			—			—
Receipt of true–up payment related to WesternGeco		13.0			—			—
Net proceeds from sale of business and interest in affiliate		3.7			58.7			24.0
Investments in affiliates		—			(7.1	)		(38.1	)

Net cash flows from continuing operations		(465.3	)		(196.3	)		(360.7	)
Net cash flows from discontinued operations		(0.1	)		(0.5	)		(1.5	)

Net cash flows from investing activities		(465.4	)		(196.8	)		(362.2	)


Cash flows from financing activities:
Net (repayments) borrowings of commercial paper and other short–term debt		(71.1	)		35.5			11.2
Repayment of indebtedness		—			(350.0	)		(100.0	)
Payment to terminate interest rate swap agreement		(5.5	)		—			—
Proceeds from termination of interest rate swap agreements		—			—			26.9
Proceeds from issuance of common stock		228.1			115.9			61.8
Repurchase of common stock		(98.5	)		—			(181.4	)
Dividends		(161.1	)		(153.6	)		(154.3	)

Net cash flows from financing activities		(108.1	)		(352.2	)		(335.8	)

Effect of foreign exchange rate changes on cash		(3.9	)		(14.1	)		(3.6	)

Increase (decrease) in cash and cash equivalents		378.0			220.6			(45.5	)
Cash and cash equivalents, beginning of year		319.0			98.4			143.9

Cash and cash equivalents, end of year	$	697.0		$	319.0		$	98.4


Income taxes paid	$	299.7		$	143.2		$	188.5
Interest paid	$	80.8		$	97.5		$	116.2

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Notes to Consolidated Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes”) is engaged in the oilfield services industry. Baker Hughes is a major supplier of wellbore–related products and technology services and systems to the worldwide oil and natural gas industry and provides products and services for drilling, formation evaluation, completion and production of oil and natural gas wells.

Basis of Presentation

The consolidated financial statements include the accounts of Baker Hughes and all majority owned subsidiaries (“we,” “our” or “us”). Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts and inventory valuation reserves, recoverability of long–lived assets, useful lives used in depreciation and amortization, income taxes and related valuation allowances and insurance, environmental, legal and pensions and postretirement benefit obligations.

Revenue Recognition

Our products and services are generally sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post–delivery obligations. Our products are produced in a standard manufacturing operation, even if produced to our customer’s specifications, and are sold in the ordinary course of business through our regular marketing channels. We recognize revenue for these products upon delivery, when title passes and when collectibility is reasonably assured. Provisions for estimated warranty returns or similar types of items are made at the time the related revenue is recognized. Revenue for services is recognized as the services are rendered and when collectibility is reasonably assured. Rates for services are typically priced on a per day, per meter, per man hour or similar basis.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

Short–term Investments

During 2005, we began investing in auction rate securities, which are highly liquid, variable–rate debt securities. While the underlying security has a long–term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days, creating short–term liquidity. The securities trade at par and are callable at par on any interest payment date at the option of the issuer. Interest is paid at the end of each auction period. We limit our investments in auction rate securities to securities that carry a AAA (or equivalent) rating from a recognized rating agency. The investments are classified as available–for–sale and are recorded at cost, which approximates market value.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Inventories

Inventories are stated at the lower of cost or market. Cost is determined using the first–in, first–out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.

Property and Depreciation

Property is stated at cost less accumulated depreciation, which is generally provided by using the straight–line method over the estimated useful lives of the individual assets. We manufacture a substantial portion of our rental tools and equipment and the cost of these items, which includes direct and indirect manufacturing costs, are capitalized and carried in inventory until the tool is completed. Once the tool has been completed, the cost of the tool is reflected in capital expenditures and the tool is classified as rental tools and equipment in property. Significant improvements and betterments are capitalized if they extend the useful life of the asset.

Goodwill, Intangible Assets and Amortization

Goodwill, including goodwill associated with equity method investments, and intangible assets with indefinite lives are not amortized. Intangible assets with finite useful lives are amortized either on a straight–line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

Impairment of Long–Lived Assets

We review property, intangible assets and certain other assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

We perform an annual impairment test of goodwill for each of our reporting units as of October 1, or more frequently if circumstances indicate an impairment may exist. Our reporting units are based on our organizational and reporting structure. Corporate and other assets and liabilities are allocated to the reporting units to the extent that they relate to the operations of those reporting units in determining their carrying amount. Investments in affiliates are also reviewed for impairment whenever events or changes in circumstances indicate that impairment may exist. The determination of impairment is made by comparing the carrying amount with its fair value, which is calculated using a combination of a market capitalization and discounted cash flow approach.

Income Taxes

We use the liability method for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.

Deferred income taxes are provided for the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities. Deferred tax assets are also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We do provide for the U.S. and additional non–U.S. taxes on earnings anticipated to be repatriated from our non–U.S. subsidiaries.

We operate in more than 90 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Product Warranties

We sell certain products with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, repair at no cost to the customer or the issuance of a credit to the customer. We accrue amounts for estimated warranty claims based upon current and historical product sales data, warranty costs incurred and any other related information known to us.

Environmental Matters

Remediation costs are accrued based on estimates of known environmental remediation exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based on internal evaluations and are not discounted. Such accruals are recorded when it is probable that we will be obligated to pay for environmental site evaluation, remediation or related activities, and such costs can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. As additional or more accurate information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred. Where we have been identified as a potentially responsible party in a United States federal or state “Superfund” site, we accrue our share of the estimated remediation costs of the site. This share is based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site.

Foreign Currency

The majority of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non–functional currency, are included in selling, general and administrative (“SG&A”) expense in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and losses resulting from balance sheet translation of foreign operations are also included in SG&A expense in the consolidated statements of operations as incurred. We recorded net foreign currency transaction and translation gains in SG&A in the consolidated statement of operations of $6.8 million, $4.0 million and $1.5 million in 2005, 2004 and 2003, respectively.

Derivative Financial Instruments

We monitor our exposure to various business risks including commodity price, foreign currency exchange rate and interest rate risks and occasionally use derivative financial instruments to manage the impact of certain of these risks. Our policies do not permit the use of derivative financial instruments for speculative purposes. We use foreign currency forward contracts to hedge certain firm commitments and transactions denominated in foreign currencies. We use interest rate swaps to manage interest rate risk.

At the inception of any new derivative, we designate the derivative as a cash flow or fair value hedge or we determine the derivative to be undesignated as a hedging instrument as the facts dictate. We document all relationships between the hedging instruments and the hedged items, as well as our risk management objectives and strategy for undertaking various hedge transactions. We assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged item at both the inception of the hedge and on an ongoing basis.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Stock–Based Compensation

As allowed under Statement of Financial Accounting Standards (“SFAS”) No. 123,Accounting for Stock–Based Compensation, we account for compensation related to stock options and our employee stock purchase plan using the intrinsic value method of accounting in accordance with Accounting Principles Board Opinion No. 25 (“APB No. 25”),Accounting for Stock Issued to Employees. Under this method, compensation expense is recognized only for the difference between the quoted market price of the stock at the measurement date less the amount, if any, the employee is required to pay for the stock. Our reported net income does not include any compensation expense associated with our employee stock purchase plan or with stock option awards because the exercise prices of our stock option awards equal the market prices of the underlying stock when granted and because our employee stock purchase plan is non compensatory. Our reported net income does include compensation expense associated with restricted stock awards.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued the revised SFAS No. 123,Share–Based Payment(“SFAS No. 123(R)”). SFAS No. 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) requires an entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant–date fair value of the award. That cost will be recognized over the period in which an employee is required to provide service in exchange for the award. SFAS No. 123(R) also requires an entity to initially measure the cost of employee services rendered in exchange for an award of liability instruments at its current fair value with the fair value remeasured at each subsequent reporting date through the settlement date. Changes in the fair value during the required service period are to be recognized as compensation cost over that period.

SFAS No. 123(R) clarified the accounting in SFAS No. 123 related to estimating the service period for employees that are or become retirement eligible during the vesting period, requiring that the recognition of compensation expense for these employees be accelerated. This impacts the timing of expense recognition, but not the total expense to be recognized over the vesting period. In the first quarter of 2005, we adopted this new methodology on a prospective basis. The cumulative effect of this clarification is $11.8 million, net of tax, which, for purposes of calculating the pro forma disclosure, is included in our pro forma disclosure for stock–based compensation below for the year ended December 31, 2005.

If we had recognized compensation expense by applying the fair value based method to all awards as provided for under SFAS No. 123, our pro forma net income, earnings per share (“EPS”) and stock–based compensation cost would have been as follows for the years ended December 31:


	2005			2004			2003

Net income, as reported	$	878.4		$	528.6		$	128.9
Add: Stock—based compensation for restricted stock awards included in reported net income, net of tax		6.1			1.6			1.9
Deduct: Stock—based compensation determined under the fair value method, net of tax		(35.0	)		(23.1	)		(23.1	)

Pro forma net income	$	849.5		$	507.1		$	107.7


Basic EPS
As reported	$	2.59		$	1.58		$	0.38
Pro forma		2.50			1.52			0.32
Diluted EPS
As reported	$	2.57		$	1.58		$	0.38
Pro forma		2.49			1.51			0.32

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Under SFAS No. 123, the fair value of stock–based awards is calculated through the use of option pricing models. These models require a number of subjective assumptions and estimates which can significantly affect the calculated values. These include future stock price volatility, expected time to exercise, discount rates, forfeiture rates and employee turnover rates. In addition, the number of awards granted impacts the amount of expense. As a result, the above pro forma amounts may not be indicative of future amounts. The above proforma calculations were made using the Black–Scholes option pricing model with the following weighted average assumptions for the years ended December 31:


	Assumptions
							Risk–Free			Expected
	Dividend			Expected			Interest			Life
	Yield			Volatility			Rate			(In years)

2005		1.0	%		35.0	%		3.7	%		3.7
2004		1.3	%		39.9	%		2.8	%		3.5
2003		1.6	%		45.0	%		2.5	%		3.8

The weighted average fair values of options granted in 2005, 2004 and 2003 were $14.62, $11.16 and $10.25 per share, respectively.

In accordance with guidance issued by the SEC that delayed the effective date, we adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective method whereby we will recognize expense on any previously granted unvested awards over the remaining service period of the award. New awards granted after the adoption date will be expensed over the estimated service period. Based on our current estimates, we expect the impact in 2006 of the adoption of SFAS No. 123(R) to be additional expense of between $18.0 million and $20.0 million, net of tax. We are continuing to evaluate the various option pricing models and the required assumptions and estimates that will be used in determining the fair value of awards made in 2006. In addition, we have estimated the number of awards to be granted in 2006 because the final amount has not been determined. As a result, the actual amount recorded as expense in 2006 may be different from this estimated amount and this estimated amount may not be indicative of the expense we may incur in future years.

New Accounting Standards

In November 2004, the FASB issued SFAS No. 151,Inventory Costs – an Amendment of ARB No. 43, Chapter 4, which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. SFAS No. 151 was effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We adopted SFAS No. 151 on January 1, 2006 with no material impact on our consolidated financial statements.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 on December 31, 2005, which resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with certain conditional asset retirement obligations.

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20 (“APB No. 20”),Accounting Changes, and SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period—specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006.

NOTE 2. DISCONTINUED OPERATIONS

In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“SPD”), a product line group within the Completion and Production segment. SPD distributes basic supplies, products and small tools to the drilling industry. In January 2006, we signed a non–binding letter of intent for the sale of SPD. The sale is expected to close in the first quarter of 2006. This transaction is subject to the negotiation and execution of a definitive sale agreement, as well as, various conditions, including satisfactory due diligence review of SPD’s business. There can be no assurance that the transaction will be consummated.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We have reclassified the consolidated financial statements for all prior periods presented to reflect these operations as discontinued. Summarized financial information from discontinued operations is as follows for the years ended December 31:


	2005			2004			2003

Revenues:
SPD	$	32.5		$	24.2		$	19.1
BHMT		—			29.4			40.4
BIRD		—			1.6			94.2
Oil producing operations		—			—			4.2

Total	$	32.5		$	55.2		$	157.9


Income (loss) before income taxes:
SPD	$	7.7		$	4.7		$	3.3
BHMT		—			1.1			3.5
BIRD		—			(0.2	)		(16.9	)
Oil producing operations		—			—			1.8

Total		7.7			5.6			(8.3	)

Income taxes:
SPD		(2.8	)		(1.8	)		(1.2	)
BHMT		—			(0.3	)		(1.3	)
BIRD		—			0.1			6.0
Oil producing operations		—			—			(0.7	)

Total		(2.8	)		(2.0	)		2.8

Income (loss) before gain (loss) on disposal:
SPD		4.9			2.9			2.1
BHMT		—			0.8			2.2
BIRD		—			(0.1	)		(10.9	)
Oil producing operations		—			—			1.1

Total		4.9			3.6			(5.5	)

Gain (loss) on disposal, net of tax:					��
BHMT		—			0.2			—
BIRD		—			(0.5	)		(37.4	)
Oil producing operations		—			—			4.1
EIMCO		—			—			(2.5	)

Total		—			(0.3	)		(35.8	)

Income (loss) from discontinued operations	$	4.9		$	3.3		$	(41.3	)

Assets and liabilities of discontinued operations are as follows for the years ended December 31:


	2005		2004

Accounts receivable, net	$	6.0	$	4.9
Inventories		8.8		9.9
Property, net		1.8		1.9

Assets of discontinued operations	$	16.6	$	16.7


Accounts payable	$	2.7	$	2.2
Accrued employee compensation		0.7		0.4
Other accrued liabilities		0.4		0.3

Liabilities of discontinued operations	$	3.8	$	2.9

NOTE 3. ACQUISITIONS

In December 2005, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million in cash, which is included in the Completion and Production segment. As a result of the acquisition and based on preliminary estimates of fair values, we recorded approximately $19.5 million of goodwill and intangible assets, which may be revised based on the final purchase price allocations. The purchase price was preliminarily allocated based on the fair values of the assets acquired and liabilities assumed in the acquisition. Pro forma results of the operations have not been presented because the effects of the acquisition were not material to our consolidated financial statements. Under the terms of the Purchase Agreement, the former

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

owners of Zertech are entitled to additional purchase price consideration of up to approximately $14.0 million based on the performance of the business during 2006, 2007 and 2008.

In 2003, we obtained a 50% interest in the QuantX Wellbore Instrumentation venture (“QuantX”), which is engaged in permanent in—well monitoring. Through August 2005, we accounted for our ownership in QuantX using the equity method of accounting. In August 2005, we exercised our right to acquire the remaining 50% interest in QuantX and began to consolidate QuantX’s accounts and discontinued using the equity method of accounting. In October 2005, we finalized the purchase of the remaining 50% interest in QuantX for $27.2 million, subject to final purchase price adjustments. Based on our carrying value of our existing investment in QuantX of $35.5 million and the additional consideration of $27.2 million, we recorded approximately $28.4 million of goodwill and $19.6 million of intangibles. We also assigned $5.1 million to in—process research and development that was written off in October 2005 at the date of acquisition. This write—off is included in research and development expenses, which are included in cost of revenues in the consolidated statement of operations. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed of QuantX. The fair values were determined using a discounted cash flow approach. Pro forma results of operations have not been presented because the effect of this acquisition was not material to our consolidated financial statements. QuantX is included in the Completion and Production segment.

In 2002, we entered into a venture, Luna Energy, L.L.C. (“Luna”), in which we had a 40% interest and that we accounted for using the equity method of accounting. In December 2004, we acquired the remaining 60% interest in Luna for $1.0 million in cash. As a result of the acquisition, we have recorded approximately $19.0 million of goodwill and $5.5 million of intangible assets. We also assigned $1.8 million to in—process research and development that was written off at the date of acquisition. This write—off is included in research and development expenses, which are included in cost of revenues in the consolidated statement of operations. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed of Luna. The fair values were determined using a discounted cash flow approach. Pro forma results of operations have not been presented because the effect of this acquisition was not material to our consolidated financial statements. Luna is included in the Completion and Production segment.

In 2003, we made two acquisitions having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. As a result of these acquisitions, we recorded approximately $3.9 million of goodwill and $9.6 million of intangible assets. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed in each of these acquisitions. Pro forma results of operations have not been presented because the effects of these acquisitions were not material to our consolidated financial statements on either an individual or aggregate basis.

NOTE 4. REVERSAL OF RESTRUCTURING CHARGE

In 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and recorded a restructuring charge of $29.5 million. Included in the restructuring charge was $1.1 million for a contractual obligation related to an oil and natural gas property in Angola. The property was sold in 2003, and we reversed the liability related to this contractual obligation.

NOTE 5. INCOME TAXES

The provision for income taxes on income from continuing operations is comprised of the following for the years ended December 31:


	2005		2004		2003

Current:
United States	$	146.3	$	51.7	$	1.6
Foreign		251.1		150.5		164.1

Total current		397.4		202.2		165.7

Deferred:
United States		7.0		45.4		(38.1	)
Foreign		0.4		3.0		18.0

Total deferred		7.4		48.4		(20.1	)

Provision for income taxes	$	404.8	$	250.6	$	145.6

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The geographic sources of income from continuing operations before income taxes are as follows for the years ended December 31:


	2005		2004		2003

United States	$	409.6	$	213.9	$	(137.4	)
Foreign		869.6		562.0		458.8

Income from continuing operations before income taxes	$	1,279.2	$	775.9	$	321.4

Tax benefits of $19.8 million, $12.5 million and $1.5 million associated with the exercise of employee stock options were allocated to equity and recorded in capital in excess of par value in the years ended December 31, 2005, 2004 and 2003, respectively.

The provision for income taxes differs from the amount computed by applying the U.S. statutory income tax rate to income from continuing operations before income taxes for the reasons set forth below for the years ended December 31:


	2005			2004			2003

Statutory income tax at 35%	$	447.7		$	271.6		$	112.5
Effect of WesternGeco operations		4.1			1.8			36.3
Effect of foreign operations		(46.0	)		(28.3	)		(5.8	)
Net tax charge related to foreign losses		5.5			4.0			4.9
State income taxes — net of U.S. tax benefit		8.8			3.4			4.0
IRS audit agreement and refund claims		(4.3	)		—			(3.3	)
Cumulative tax effect of SRP		(10.6	)		—			—
Other — net		(0.4	)		(1.9	)		(3.0	)

Provision for income taxes	$	404.8		$	250.6		$	145.6

During 2005 and 2004, we recognized an incremental effect of $4.1 million and $1.8 million, respectively, of additional taxes attributable to our portion of the operations of WesternGeco. This consists of $3.3 million of tax expense associated with the $13.3 million WesternGeco true—up payment received from Schlumberger in 2005 and the state tax effect related to increased income in the U.S. in 2005 and 2004.

During 2003, we recognized an incremental effect of $36.3 million of additional taxes related to our investment in WesternGeco. Of this amount, $15.9 million related to the reduction in the carrying value of our equity investment in WesternGeco, for which there was no tax benefit. The remaining $20.4 million arose from operations of the venture due to: (i) the venture being taxed in certain foreign jurisdictions based on a deemed profit basis, which is a percentage of revenues rather than profits, and (ii) unbenefitted foreign losses of the venture, which are operating losses and impairment and restructuring charges in certain foreign jurisdictions where there was no current tax benefit and where a deferred tax asset was not recorded due to the uncertainty of realization.

In 2005 and 2003, we recognized a benefit of $4.3 million and $3.3 million, respectively, as the result of refund claims filed in the U.S.

In 2005, we recognized a $10.6 million deferred tax asset attributable to the cumulative temporary difference between the carrying values of our Supplemental Retirement Plan (“SRP”) for financial reporting and income tax purposes, which had the effect of reducing current year tax expense.

We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and /or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. While we have provided for the taxes that we believe will ultimately be payable as a result of these assessments, the aggregate assessments are approximately $34.1 million in excess of the taxes provided for in our consolidated financial statements.

In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we consider it probable that the taxes ultimately payable will exceed the amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in SFAS No. 5,Accounting for Contingencies, and are included in both income taxes in current liabilities and in deferred income taxes and other tax liabilities in the consolidated balance sheets.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects of our temporary differences and carryforwards are as follows at December 31:


	2005			2004

Deferred tax assets:
Receivables	$	9.9		$	9.7
Inventory		125.9			110.6
Property		40.8			5.8
Employee benefits		28.7			25.0
Other accrued expenses		31.5			26.5
Operating loss carryforwards		44.1			49.1
Tax credit carryforwards		46.7			76.9
Capitalized research and development costs		63.5			74.1
Other		46.0			41.3

Subtotal		437.1			419.0
Valuation allowances		(42.4	)		(36.7	)

Total		394.7			382.3


Deferred tax liabilities:
Goodwill		113.4			105.4
Undistributed earnings of foreign subsidiaries		61.7			34.7
Other		20.7			9.1

Total		195.8			149.2

Net deferred tax asset	$	198.9		$	233.1

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for operating loss carryforwards in certain non—U.S. jurisdictions where our operations have decreased, currently ceased or we have withdrawn entirely.

We have provided for U.S. and additional foreign taxes for the anticipated repatriation of certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our foreign subsidiaries above the amount already provided to be indefinitely reinvested, as we have no intention to repatriate these earnings. These additional foreign earnings could become subject to additional tax if remitted, or deemed remitted, as a dividend; however, it is not practicable to estimate the additional amount of taxes payable.

At December 31, 2005, we had approximately $41.0 million of foreign tax credits expiring in varying amounts between 2014 and 2016 and $5.7 million of state tax credits which may be carried forward indefinitely under current state law. The operating loss carryforwards without a valuation allowance will expire in varying amounts over the next twenty years.

NOTE 6. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted EPS computations is as follows for the years ended December 31:


	2005		2004		2003

Weighted average common shares outstanding for basic EPS		339.4		333.8		334.9
Effect of dilutive securities — stock plans		2.1		1.8		1.0

Adjusted weighted average common shares outstanding for diluted EPS		341.5		335.6		335.9


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than average market price for the period		0.7		4.6		6.8

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 7. INVENTORIES

Inventories are comprised of the following at December 31:


	2005		2004

Finished goods	$	914.5	$	860.3
Work in process		134.2		107.3
Raw materials		77.6		57.7

Total	$	1,126.3	$	1,025.3

NOTE 8. INVESTMENTS IN AFFILIATES

We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates is WesternGeco, a seismic venture in which we own 30% and Schlumberger Limited (“Schlumberger”) owns 70%.

In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true—up payment was to be made by either of the parties based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic data libraries during the four—year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. In August 2005, we received $13.3 million from Schlumberger related to the true—up payment. We recorded $13.0 million as a reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest income. The income tax effect of $3.3 million related to this payment is included in our provision for income taxes for the year ended December 31, 2005.

During 2005, we received distributions of $30.0 million from WesternGeco, which were recorded as reductions in the carrying value of our investment.

Included in the caption “Equity in income (loss) of affiliates” in our consolidated statement of operations for 2003 is $135.7 million for our share of $452.0 million of certain impairment and restructuring charges taken by WesternGeco in 2003. The charges related to the impairment of WesternGeco’s multiclient seismic library and rationalization of WesternGeco’s marine seismic fleet. In addition, as a result of the continued weakness in the seismic industry, we evaluated the value of our investment in WesternGeco and recorded an impairment loss of $45.3 million in 2003 to write—down the investment to its fair value. The fair value was determined using a combination of a market capitalization and discounted cash flow approach.

In February 2004, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, for $35.8 million, of which $7.4 million was placed in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. In May 2005, we received $3.7 million from the release of a portion of the amount held in escrow. The remainder is expected to be released in the first quarter of 2006, subject to the indemnity obligations under the sales agreement. In 2004, we recognized a gain on the sale of $1.3 million, net of tax of $1.5 million.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Summarized unaudited combined financial information for the affiliates, in which we account for our interests using the equity method of accounting, is as follows as of December 31:


	2005		2004

Combined operating results:
Revenues	$	1,700.7	$	1,313.8
Operating income		327.3		131.9
Net income		279.7		124.9

Combined financial position:
Current assets	$	1,110.8	$	755.2
Noncurrent assets		1,056.6		1,162.8

Total assets	$	2,167.4	$	1,918.0


Current liabilities	$	522.7	$	423.6
Noncurrent liabilities		85.2		101.2
Stockholders’ equity		1,559.5		1,393.2

Total liabilities and stockholders’ equity	$	2,167.4	$	1,918.0

At December 31, 2005 and 2004, net accounts receivable (payable) from unconsolidated affiliates totaled $0.4 million and $(1.1) million, respectively. As of December 31, 2005 and 2004, the excess of our investment over our equity in affiliates was $239.4 million and $268.9 million, respectively.

NOTE 9. PROPERTY

Property is comprised of the following at December 31:


	Depreciation
	Period	2005			2004

Land		$	39.7		$	40.5
Buildings and improvements	5 — 40 years		611.7			616.3
Machinery and equipment	2 — 20 years		2,022.3			1,958.4
Rental tools and equipment	1 — 8 years		1,157.5			1,097.5

Total property			3,831.2			3,712.7
Accumulated depreciation			(2,475.7	)		(2,380.5	)

Property — net		$	1,355.5		$	1,332.2

NOTE 10. GOODWILL AND INTANGIBLE ASSETS

The changes in the carrying amount of goodwill are detailed below by segment:


	Drilling		Completion
	and		and
	Evaluation		Production			Total

Balance as of December 31, 2003	$	895.0	$	344.4		$	1,239.4
Goodwill from acquisitions during the period		5.6		19.0			24.6
Translation adjustments and other		2.3		0.7			3.0

Balance as of December 31, 2004		902.9		364.1			1,267.0
Goodwill from acquisitions during the period		—		48.1			48.1
Translation adjustments and other		1.2		(0.5	)		0.7

Balance as of December 31, 2005	$	904.1	$	411.7		$	1,315.8

We perform an annual impairment test of goodwill as of October 1 of every year. There were no impairments of goodwill in 2005, 2004 or 2003 related to the annual impairment test.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Intangible assets are comprised of the following at December 31:


	2005							2004
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology based	$	204.8	$	(71.3	)	$	133.5	$	190.2	$	(58.8	)	$	131.4
Contract based		11.1		(6.5	)		4.6		11.0		(4.8	)		6.2
Marketing related		6.1		(5.6	)		0.5		6.1		(5.6	)		0.5
Customer based		6.4		(0.4	)		6.0		0.6		(0.2	)		0.4
Other		1.2		(0.7	)		0.5		1.2		(0.8	)		0.4

Total amortizable intangible assets		229.6		(84.5	)		145.1		209.1		(70.2	)		138.9
Marketing related intangible asset with an indefinite useful life		18.3		—			18.3		16.2		—			16.2

Total	$	247.9	$	(84.5	)	$	163.4	$	225.3	$	(70.2	)	$	155.1

Intangible assets are amortized either on a straight—line basis with estimated useful lives ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits of the intangible assets are consumed, which range from 15 to 30 years.

Amortization expense included in net income for the years ended December 31, 2005, 2004 and 2003 was $15.2 million, $14.9 million and $13.5 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years is expected to be within the range of $11.6 million to $18.2 million.

NOTE 11. INDEBTEDNESS

Total debt consisted of the following at December 31:


	2005		2004

6.25% Notes due January 2009 with an effective interest rate of 4.65%, net of unamortized discount of $1.0 at December 31, 2005 ($1.3 at December 31, 2004)	$	339.5	$	348.2

6.00% Notes due February 2009 with an effective interest rate of 6.11%, net of unamortized discount of $0.5 at December 31, 2005 ($0.7 at December 31, 2004)		199.5		199.3

8.55% Debentures due June 2024 with an effective interest rate of 8.80%, net of unamortized discount of $2.5 at December 31, 2005 ($2.6 at December 31, 2004)		147.5		147.4

6.875% Notes due January 2029 with an effective interest rate of 7.08%, net of unamortized discount of $8.5 at December 31, 2005 ($8.7 at December 31, 2004)		391.5		391.3

Other debt		9.9		76.1

Total debt		1,087.9		1,162.3
Less short—term debt and current maturities		9.9		76.0

Long—term debt	$	1,078.0	$	1,086.3

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

payment defaults to lenders under the facility, covenant defaults and other customary defaults. At December 31, 2005, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the year ended December 31, 2005; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2005, we had no outstanding commercial paper.

We realized net gains as a result of terminating various interest rate swap agreements prior to their scheduled maturities. The net gains were deferred and are being amortized as a net reduction of interest expense over the remaining life of the underlying debt securities. The unamortized deferred gains of $15.5 million and $26.8 million are included in the 6.25% Notes due January 2009 and reported in long—term debt in the consolidated balance sheets at December 31, 2005 and 2004, respectively.

Maturities of debt at December 31, 2005 are as follows: 2006 — $9.9 million; 2007 — $0.0 million; 2008 — $0.0 million; 2009 — $539.0 million; 2010 — $0.0 million and $539.0 million thereafter.

NOTE 12. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and short—term investments, receivables, payables, debt and foreign currency forward contracts. Except as described below, the estimated fair value of such financial instruments at December 31, 2005 and 2004 approximates their carrying value as reflected in our consolidated balance sheets. The fair value of our debt and foreign currency forward contracts has been estimated based on year—end quoted market prices.

The estimated fair value of total debt at December 31, 2005 and 2004 was $1,233.6 million and $1,315.0 million, respectively, which differs from the carrying amounts of $1,087.9 million and $1,162.3 million, respectively, included in our consolidated balance sheet.

Interest Rate Swap Agreements

In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. The interest rate swap agreement was designated and qualified as a fair value hedging instrument. The interest rate swap agreement was fully effective, resulting in no gain or loss recorded in the consolidated statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $2.3 million liability at December 31, 2004, based on quoted market prices for contracts with similar terms and maturity dates.

Foreign Currency Forward Contracts

At December 31, 2005, we had entered into several foreign currency forward contracts with notional amounts aggregating $65.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including the British Pound Sterling, the Norwegian Krone, the Euro and the Brazilian Real. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of December 31, 2005 for contracts with similar terms and maturity dates, we recorded a gain of $0.1 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

At December 31, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including the British Pound Sterling, the Norwegian Krone, the Euro and the Brazilian Real. These contracts were designated and qualified as fair value hedging instruments. Based on quoted market prices as of December 31, 2004, for contracts with similar terms and maturity dates, we recorded a loss of $0.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

At December 31, 2004, we had also entered into several foreign currency forward contracts with notional amounts aggregating $122.4 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. The funding of such imbalances was supported by short–term intercompany borrowing commitments that had definitive amounts and funding dates. All funding took place before December 31, 2005. These foreign currency forward contracts were designated as cash flow hedging instruments and were fully effective. Based on quoted market prices as of December 31, 2004, for contracts with similar terms and maturity dates, we recorded a loss of $0.1 million to adjust these foreign currency forward contracts to their fair market value. The loss was recorded in other comprehensive income in the consolidated balance sheet.

Additionally, during 2005 and 2004, we entered into and settled foreign currency forward contracts to hedge exposure to currency fluctuations for specific transactions or balances. The impact on our consolidated statements of operations was not significant for these contracts either individually or in the aggregate.

The counterparties to our foreign currency forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency exchange rate differential.

Concentration of Credit Risk

We sell our products and services to numerous companies in the oil and natural gas industry. Although this concentration could affect our overall exposure to credit risk, we believe that we are exposed to minimal risk since the majority of our business is conducted with major companies within the industry. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral for our accounts receivable. In some cases, we will require payment in advance or security in the form of a letter of credit or bank guarantee.

We maintain cash deposits with major banks that may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that the risk of any loss is minimal.

NOTE 13. SEGMENT AND RELATED INFORMATION

In 2005, we reorganized our operating divisions into two separate segments: the Drilling and Evaluation segment, which consists of the Baker Atlas, Baker Hughes Drilling Fluids, Hughes Christensen and INTEQ divisions, and the Completion and Production segment, which consists of the Baker Oil Tools, Baker Petrolite and Centrilift divisions. The Completion and Production segment also includes our Production Optimization business unit. The reorganization was done to align product lines based on the types of products and services provided to our customers, to provide additional focus on our product lines and technology and to be able to more effectively serve our customers.

Accordingly, we are reporting our results under three segments: Drilling and Evaluation, Completion and Production and WesternGeco. Divisions in the Drilling and Evaluation segment generally provide services and products used directly in the drilling and formation evaluation of oil and natural gas wells. Divisions in the Completion and Production segment generally provide services and products used to complete wells, rework existing wells and enhance or initiate production from new wells.

We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions is affected by similar economic conditions. They also operate in the same markets, which include all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance. All prior period segment information has been restated to reflect these changes.

The accounting policies of our segments are the same as those described in Note 1 of Notes to Consolidated Financial Statements. We evaluate the performance of our segments based on segment profit (loss), which is defined as income from continuing operations before income taxes, accounting changes, restructuring charge reversals, impairment of assets and interest income and expense.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Summarized financial information is shown in the following table. The “Corporate and Other” column includes corporate–related items, results of insignificant operations and, as it relates to segment profit (loss), income and expense not allocated to the segments, including restructuring charge reversals and impairment of assets. The “Corporate and Other” column, for all periods presented, also includes assets of discontinued operations.


	Drilling			Completion
	and			and					Total			Corporate
	Evaluation			Production		WesternGeco			Oilfield			and Other			Total

2005
Revenues	$	3,694.2		$	3,490.0	$	—		$	7,184.2		$	1.3		$	7,185.5
Equity in income of affiliates		1.1			2.2		96.7			100.0			0.1			100.1
Segment profit (loss)		766.3			682.4		96.7			1,545.4			(266.2	)		1,279.2
Total assets		3,221.9			2,882.6		688.0			6,792.5			1,014.9			7,807.4
Investment in affiliates		6.1			12.2		660.6			678.9			—			678.9
Capital expenditures		347.8			129.6		—			477.4			0.9			478.3
Depreciation and amortization		232.7			121.1		—			353.8			28.6			382.4

2004
Revenues	$	3,033.3		$	3,042.9	$	—		$	6,076.2		$	3.4		$	6,079.6
Equity in income (loss) of affiliates		0.4			1.9		34.5			36.8			(0.5	)		36.3
Segment profit (loss)		510.4			514.4		34.5			1,059.3			(283.4	)		775.9
Total assets		2,893.1			2,625.4		643.9			6,162.4			658.9			6,821.3
Investment in affiliates		5.2			48.3		624.6			678.1			—			678.1
Capital expenditures		236.4			110.4		—			346.8			1.4			348.2
Depreciation and amortization		226.7			116.7		—			343.4			28.2			371.6

2003
Revenues	$	2,653.8		$	2,579.5	$	—		$	5,233.3		$	—		$	5,233.3
Equity in income (loss) of affiliates		(0.6	)		1.8		(9.8	)		(8.6	)		(129.2	)		(137.8	)
Segment profit (loss)		367.5			388.4		(10.1	)		745.8			(424.4	)		321.4
Total assets		2,820.2			2,451.6		606.0			5,877.8			538.7			6,416.5
Investment in affiliates		9.6			64.8		588.5			662.9			28.4			691.3
Capital expenditures		286.4			114.2		—			400.6			3.3			403.9
Depreciation and amortization		210.1			109.9		—			320.0			27.3			347.3

For the years ended December 31, 2005, 2004 and 2003, there were no revenues attributable to one customer that accounted for more than 10% of total revenues.

The following table presents the details of “Corporate and Other” segment loss for the years ended December 31:


	2005			2004			2003

Corporate and other expenses	$	(211.9	)	$	(206.6	)	$	(146.7	)
Interest–net		(54.3	)		(76.8	)		(97.8	)
Impairment of investment in affiliate		—			—			(45.3	)
Reversal of restructuring charge		—			—			1.1
Impairment and restructuring charges related to investment in affiliate		—			—			(135.7	)

Total	$	(266.2	)	$	(283.4	)	$	(424.4	)

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The following table presents the details of “Corporate and Other” total assets at December 31:


	2005		2004		2003

Current deferred tax asset	$	29.4	$	61.7	$	35.7
Property		78.5		107.6		134.7
Accounts receivable		9.3		26.5		50.0
Other tangible assets		109.3		115.6		107.5
Investment in affiliate		—		—		28.4
Assets of discontinued operations		16.6		16.7		62.4
Cash and other assets		771.8		330.8		120.0

Total	$	1,014.9	$	658.9	$	538.7

The following table presents consolidated revenues by country based on the location of the use of the products or services for the years ended December 31:


	2005		2004		2003

United States	$	2,576.1	$	2,132.9	$	1,873.0
Canada		472.8		389.1		332.3
United Kingdom		402.9		329.2		295.8
Norway		376.1		310.7		328.9
China		218.5		192.9		117.6
Venezuela		176.8		163.3		130.3
Saudi Arabia		170.6		89.3		74.4
Other countries		2,791.7		2,472.2		2,081.0

Total	$	7,185.5	$	6,079.6	$	5,233.3

The following table presents net property by country based on the location of the asset at December 31:


	2005		2004		2003

United States	$	734.4	$	724.6	$	789.2
United Kingdom		133.2		146.0		143.4
Canada		67.9		56.4		54.4
Germany		49.4		44.4		43.3
Norway		43.8		46.8		47.5
United Arab Emirates		29.0		15.4		19.0
Angola		26.0		16.5		27.6
Other countries		271.8		282.1		268.8

Total	$	1,355.5	$	1,332.2	$	1,393.2

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 14. EMPLOYEE STOCK PLANS

We have stock option plans that provide for the issuance of incentive and non—qualified stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. These stock options generally vest over three years. Vested options are exercisable in part or in full at any time prior to the expiration date of ten years from the date of grant. As of December 31, 2005, 11.3 million shares were available for future option grants. The following table summarizes the activity for our stock option plans:


				Weighted
	Number			Average
	of Shares			Exercise Price
	(In thousands)			Per Share

Outstanding at December 31, 2002		10,868		$	32.68
Granted		2,481			30.92
Exercised		(1,005	)		21.44
Forfeited		(515	)		38.97

Outstanding at December 31, 2003		11,829			32.99
Granted		2,495			37.68
Exercised		(3,764	)		25.62
Forfeited		(255	)		39.07

Outstanding at December 31, 2004		10,305			36.67
Granted		1,321			49.63
Exercised		(5,594	)		36.96
Forfeited		(457	)		44.01

Outstanding at December 31, 2005		5,575		$	38.84


Shares exercisable at December 31:
2005		2,420		$	35.38
2004		6,417		$	38.02
2003		7,611		$	33.80

The following table summarizes information for stock options outstanding at December 31, 2005:


	Outstanding						Exercisable
			Weighted
			Average
			Remaining		Weighted				Weighted
			Contractual		Average				Average
Range of Exercise	Shares		Life		Exercise		Shares		Exercise
Prices	(In thousands)		(In years)		Price		(In thousands)		Price

$ 8.80 — $15.99		11		2.2	$	11.59		11	$	11.59
16.08 — 21.00		140		2.6		20.64		140		20.64
21.06 — 26.07		375		4.5		24.48		374		24.49
28.25 — 39.23		2,861		7.3		34.65		1,046		33.08
41.06 — 56.21		2,188		6.8		48.08		849		45.75

Total		5,575		6.8	$	38.84		2,420	$	35.38

We also have an employee stock purchase plan whereby eligible employees may purchase shares of our common stock at a price equal to 85% of the lower of the closing price of our common stock on the first or last trading day of the calendar year. A total of 3.4 million shares are remaining for issuance under the plan. Employees purchased 0.6 million, 0.8 million and 0.8 million shares in the three years ending December 31, 2005, 2004 and 2003, respectively.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We have a plan under which restricted stock is issued to directors and executive officers and beginning in 2005 to other key employees. The fair value of the restricted stock on the date of grant is amortized ratably over the vesting period. The following table summarizes the restricted stock awarded during the years ended December 31:


	2005		2004		2003

Number of shares of restricted stock awarded (in thousands)		460		163		10
Fair value of restricted stock at date of grant (in millions)	$	20.4	$	6.9	$	0.3

NOTE 15. EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K. and Germany. We make annual contributions to the plans in amounts at least necessary to meet minimum governmental funding requirements. The measurements of plan assets and obligations are as of October 1 of each year presented.

The reconciliation of the beginning and ending balances of the projected benefit obligations (“PBO”) and fair value of plan assets and the funded status of the plans are as follows for the years ended December 31:


	U.S. Pension Benefits						Non—U.S. Pension Benefits
	2005			2004			2005			2004

Change in projected benefit obligation:
Projected benefit obligation at beginning of year	$	203.8		$	175.6		$	261.0		$	269.2
Service cost		22.8			20.6			2.2			2.1
Interest cost		11.9			10.6			13.8			12.7
Actuarial loss		10.9			6.7			47.8			7.9
Benefits paid from fund		(11.3	)		(9.7	)		(5.3	)		(5.8	)
Curtailments/settlements (gain) loss		—			—			(1.2	)		(42.2	)
Other		0.7			—			0.2			—
Exchange rate adjustments		—			—			(31.0	)		17.1

Projected benefit obligation at end of year		238.8			203.8			287.5			261.0


Change in plan assets:
Fair value of plan assets at beginning of year		284.9			237.9			158.3			135.2
Actual gain on plan assets		45.9			33.4			30.7			18.3
Employer contributions		34.6			23.3			45.6			18.4
Benefits paid from fund		(11.3	)		(9.7	)		(5.3	)		(5.8	)
Settlements (gain) loss		—			—			(1.3	)		(17.6	)
Exchange rate adjustments		—			—			(20.4	)		9.8

Fair value of plan assets at end of year		354.1			284.9			207.6			158.3


Funded status — over (under)		115.3			81.1			(79.9	)		(102.7	)
Unrecognized actuarial loss		47.8			59.5			95.1			77.0
Unrecognized prior service cost		0.3			0.3			0.2			0.2

Net amount recognized		163.4			140.9			15.4			(25.5	)
Employer contributions/benefits paid — October to December		28.8			32.5			8.3			36.1

Net amount recognized in the balance sheet	$	192.2		$	173.4		$	23.7		$	10.6

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We report prepaid benefit cost in other assets and accrued benefit and minimum liabilities in pensions and postretirement benefit obligations in the consolidated balance sheet. The amounts recognized in the consolidated balance sheet are as follows at December 31:


	U.S. Pension Benefits						Non—U.S. Pension Benefits
	2005			2004			2005			2004

Prepaid benefit cost	$	203.6		$	185.0		$	46.2		$	33.8
Accrued benefit liability		(11.4	)		(11.6	)		(22.5	)		(23.2	)
Minimum liability		(14.2	)		(14.9	)		(86.6	)		(68.3	)
Intangible asset		0.1			0.1			—			—
Accumulated other comprehensive loss		14.1			14.8			86.6			68.3

Net amount recognized in the balance sheet	$	192.2		$	173.4		$	23.7		$	10.6

Weighted average assumptions used to determine benefit obligations for these plans are as follows for the years ended December 31:


	U.S. Pension Benefits						Non—U.S. Pension Benefits
	2005			2004			2005			2004

Discount rate		5.50	%		6.00	%		4.90	%		5.67	%
Rate of compensation increase		4.00	%		3.50	%		3.38	%		3.53	%

The accumulated benefit obligation (“ABO”) is the actuarial present value of pension benefits attributed to employee service to date and present compensation levels. The ABO differs from the PBO in that the ABO does not include any assumptions about future compensation levels. The ABO for all U.S. plans was $232.9 million and $201.8 million at December 31, 2005 and 2004, respectively. The ABO for all non—U.S. plans was $279.2 million and $252.5 million at December 31, 2005 and 2004, respectively.

Information for the plans with ABOs in excess of plan assets is as follows at December 31:


	U.S. Pension Benefits				Non—U.S. Pension Benefits
	2005		2004		2005		2004

Projected benefit obligation	$	108.0	$	78.6	$	281.7	$	256.3
Accumulated benefit obligation		102.2		76.6		274.6		248.2
Fair value of plan assets		77.9		40.3		203.0		153.3

The components of net periodic benefit cost are as follows for the years ended December 31:


	U.S. Pension Benefits									Non—U.S. Pension Benefits
	2005			2004			2003			2005			2004			2003

Service cost	$	22.8		$	20.6		$	16.6		$	2.2		$	2.1		$	5.4
Interest cost		11.9			10.6			9.1			13.8			12.7			12.1
Expected return on plan assets		(25.9	)		(20.7	)		(15.0	)		(13.2	)		(9.2	)		(8.1	)
Amortization of prior service cost		—			0.1			—			—			—			(0.1	)
Recognized actuarial loss		2.6			4.0			6.5			2.6			4.6			2.9
Special termination benefit cost		0.7			—			—			—			—			—
Recognized curtailment (gain) loss		—			—			—			—			(2.1	)		—
Recognized settlement (gain) loss		—			—			—			0.2			(1.1	)		—

Net periodic benefit cost	$	12.1		$	14.6		$	17.2		$	5.6		$	7.0		$	12.2

Weighted average assumptions used to determine net costs for these plans are as follows for the years ended December 31:


	U.S. Pension Benefits									Non—U.S Pension Benefits
	2005			2004			2003			2005			2004			2003

Discount rate		6.00	%		6.25	%		6.75	%		5.67	%		5.37	%		5.82	%
Expected rate of return on plan assets		8.50	%		8.50	%		8.50	%		7.38	%		7.28	%		7.41	%
Rate of compensation increase		3.50	%		3.50	%		4.00	%		3.53	%		2.50	%		3.40	%

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

In selecting the expected rate of return on plan assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for the benefits of these plans. This includes considering the trusts’ asset allocation and the expected returns likely to be earned over the life of the plans.

The weighted—average asset allocations by asset category for the plans are as follows at December 31:


	Percentage of Plan Assets
	U.S. Pension Benefits									Non—U.S Pension Benefits
Asset Category	Target			2005			2004			Target			2005			2004

Equity securities		68	%		69	%		68	%		55	%		58	%		65	%
Debt securities		25	%		21	%		23	%		21	%		20	%		21	%
Real estate		7	%		9	%		8	%		21	%		17	%		9	%
Other		—			1	%		1	%		3	%		5	%		5	%

Total		100	%		100	%		100	%		100	%		100	%		100	%

We have an investment committee that meets quarterly to review the portfolio returns and to determine asset—mix targets based on asset/liability studies. A third—party investment consultant assisted us in developing an asset allocation strategy to determine our expected rate of return and expected risk for various investment portfolios. The investment committee considered these studies in the formal establishment of the current asset—mix targets based on the projected risk and return levels for each asset class.

In 2006, we expect to contribute between $2.0 million and $3.0 million to the U.S. pension plans and between $16.0 million and $20.0 million to the non—U.S. pension plans.

The expected benefit payments related to our U.S. pension plans for each of the five years in the period ending December 31, 2010 are $12.7 million, $13.4 million, $14.6 million, $16.8 million and $18.9 million, respectively, and $141.7 million in the aggregate for the five years thereafter. The expected benefit payments related to our non—U.S. pension plans for each of the five years in the period ending December 31, 2010 are $7.1 million, $9.6 million, $4.4 million, $3.6 million and $4.4 million, respectively, and $27.0 million in the aggregate for the five years thereafter. These payments reflect benefits attributable to estimated future employee service and are primarily funded from plan assets.

Postretirement Welfare Benefits

We provide certain postretirement health care and life insurance benefits (“postretirement welfare benefits”) to substantially all U.S. employees who retire and have met certain age and service requirements. The plan is unfunded. The measurement of plan obligations is as of October 1 of each year presented. The reconciliation of the beginning and ending balances of benefit obligations and the funded status of the plan is as follows for the years ended December 31:


	2005			2004

Change in benefit obligation:
Accumulated benefit obligation at beginning of year	$	169.5		$	174.8
Service cost		6.1			5.5
Interest cost		9.7			9.6
Actuarial (gain) loss		12.5			(7.1	)
Benefits paid		(13.3	)		(13.3	)

Accumulated benefit obligation at end of year		184.5			169.5


Funded status — over (under)		(184.5	)		(169.5	)
Unrecognized actuarial loss		45.4			34.9
Unrecognized prior service cost		7.2			7.8

Net amount recognized		(131.9	)		(126.8	)
Benefits paid — October to December		3.3			3.6

Net amount recognized		(128.6	)		(123.2	)
Less current portion reported in accrued employee compensation		(15.5	)		(16.3	)

Long—term portion reported in pensions and postretirement benefit obligations	$	(113.1	)	$	(106.9	)

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Weighted average discount rates of 5.50% and 6.00% were used to determine postretirement welfare benefit obligations for the plan for the years ended December 31, 2005 and 2004, respectively.

The components of net periodic benefit cost are as follows for the years ended December 31:


	2005		2004		2003

Service cost	$	6.1	$	5.5	$	4.8
Interest cost		9.7		9.6		10.3
Amortization of prior service cost		0.6		0.6		0.6
Recognized actuarial loss		2.0		1.0		1.1

Net periodic benefit cost	$	18.4	$	16.7	$	16.8

Weighted average discount rates of 6.00%, 6.25% and 6.75% were used to determine net postretirement welfare benefit costs for the plan for the years ended December 31, 2005, 2004 and 2003, respectively.

Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement welfare benefits plan. The assumed health care cost trend rate used in measuring the accumulated benefit obligation for postretirement welfare benefits was increased in 2003. As of December 31, 2005, the health care cost trend rate was 10.0% for employees under age 65 and 7.0% for participants over age 65, with each declining gradually each successive year until it reaches 5.0% for both employees under age 65 and over age 65 in 2011. A one percentage point change in assumed health care cost trend rates would have had the following effects on 2005:


	One Percentage		One Percentage
	Point Increase		Point Decrease

Effect on total of service and interest cost components	$	0.6	$	(0.5	)
Effect on postretirement welfare benefit obligation		9.4		(8.5	)

The expected benefit payments related to postretirement welfare benefits are as follows for the years ending December 31:


																2011 —
	2006			2007			2008			2009			2010			2015

Gross benefit payments	$	17.4		$	18.1		$	18.9		$	19.8		$	20.3		$	115.8
Expected Medicare subsidies		(1.9	)		(2.1	)		(2.2	)		(2.4	)		(2.5	)		(13.9	)

Net benefit payments	$	15.5		$	16.0		$	16.7		$	17.4		$	17.8		$	101.9

Defined Contribution Plans

During the periods reported, generally all of our U.S. employees were eligible to participate in our sponsored Thrift Plan, which is a 401(k) plan under the Internal Revenue Code of 1986, as amended. The Thrift Plan allows eligible employees to elect to contribute from 1% to 50% of their salaries to an investment trust. Employee contributions are matched in cash by us at the rate of $1.00 per $1.00 employee contribution for the first 3% and $0.50 per $1.00 employee contribution for the next 2% of the employee’s salary. Such contributions vest immediately. In addition, we make cash contributions for all eligible employees between 2% and 5% of their salary depending on the employee’s age. Such contributions become fully vested to the employee after five years of employment. The Thrift Plan provides for ten different investment options, for which the employee has sole discretion in determining how both the employer and employee contributions are invested. Our contributions to the Thrift Plan and several other non—U.S. defined contribution plans amounted to $86.5 million, $75.5 million and $67.7 million in 2005, 2004 and 2003, respectively.

For certain non—U.S. employees who are not eligible to participate in the Thrift Plan, we provide a non—qualified defined contribution plan that provides basically the same benefits as the Thrift Plan. In addition, we provide a non—qualified supplemental retirement plan (“SRP”) for certain officers and employees whose benefits under the Thrift Plan and/or the U.S. defined benefit pension plan are limited by federal tax law. The SRP also allows the eligible employees to defer a portion of their eligible compensation and provides for employer matching and base contributions pursuant to limitations. Both non—qualified plans are fully funded and invested through trusts, and the assets and corresponding liabilities are included in our consolidated balance sheet. Our contributions to these non—qualified plans were $7.2 million, $6.1 million and $5.5 million for 2005, 2004 and 2003, respectively.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Postemployment Benefits

We provide certain postemployment disability income, medical and other benefits to substantially all qualifying former or inactive U.S. employees. Income benefits for long–term disability are provided through a fully–insured plan. The continuation of medical and other benefits while on disability (“Continuation Benefits”) are provided through a qualified self–insured plan. The accrued postemployment liability for Continuation Benefits at December 31, 2005 and 2004 was $17.5 million and $20.2 million, respectively, and is included in other liabilities in our consolidated balance sheet.

NOTE 16. COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2005, we had long–term non–cancelable operating leases covering certain facilities and equipment. The minimum annual rental commitments, net of amounts due under subleases, for each of the five years in the period ending December 31, 2010 are $74.7 million, $54.6 million, $39.2 million, $25.0 million and $16.8 million, respectively, and $103.7 million in the aggregate thereafter. We have not entered into any significant capital leases.

Litigation

We are involved in litigation or proceedings that have arisen in our ordinary business activities. We insure against these risks to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of such insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future legal proceedings. Many of these insurance policies contain deductibles or self–insured retentions in amounts we deem prudent, and for which we are responsible for payment. In determining the amount of self–insurance, it is our policy to self–insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation. We record accruals for the uninsured portion of losses related to these types of claims. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

On March 29, 2002, we announced that we had been advised that the Securities and Exchange Commission (“SEC”) and the Department of Justice (“DOJ”) are conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding anti–bribery, books and records and internal controls. The SEC has issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In addition, we have conducted internal investigations into these matters.

Our internal investigations have identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental authorities in Nigeria. The internal investigation in Nigeria was substantially completed during the first quarter of 2003 and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our consolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the internal investigations has been provided to the SEC and DOJ.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Environmental Matters

Our past and present operations include activities which are subject to extensive domestic (including U.S. federal, state and local) and international environmental regulations with regard to air and water quality and other environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance with existing laws and regulations and to minimize the possibility of significant environmental damage.

We are involved in voluntary remediation projects at some of our present and former manufacturing facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency–issued consent decree or agreed order. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. Remediation cost estimates include direct costs related to the environmental investigation, external consulting activities, governmental oversight fees, treatment equipment and costs associated with long–term operation, maintenance and monitoring of a remediation project.

We have also been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites. We participate in the process set out in the Joint Participation and Defense Agreement to negotiate with government agencies, identify other PRPs and determine each PRP’s allocation and estimate remediation costs. We have accrued what we believe to be our pro–rata share of the total estimated cost of remediation and associated management of these Superfund sites. This share is based upon the ratio that the estimated volume of waste we contributed to the site bears to the total estimated volume of waste disposed at the site. Applicable United States federal law imposes joint and several liability on each PRP for the cleanup of these sites leaving us with the uncertainty that we may be responsible for the remediation cost attributable to other PRPs who are unable to pay their share. No accrual has been made under the joint and several liability concept for those Superfund sites where our participation isde minimissince we believe that the probability that we will have to pay material costs above our volumetric share is remote. We believe there are other PRPs who have greater involvement on a volumetric calculation basis, who have substantial assets and who may be reasonably expected to pay their share of the cost of remediation. For those Superfund sites where we are a significant PRP, remediation costs are estimated to include recalcitrant parties. In some cases, we have insurance coverage or contractual indemnities from third parties to cover a portion of or the ultimate liability.

Our total accrual for environmental remediation is $17.4 million and $13.6 million, which includes accruals of $4.9 million and $3.6 million for the various Superfund sites, at December 31, 2005 and 2004, respectively. The determination of the required accruals for remediation costs is subject to uncertainty, including the evolving nature of environmental regulations and the difficulty in estimating the extent and type of remediation activity that will be utilized. We believe that the likelihood of material losses in excess of the recorded accruals is remote.

Other

In the normal course of business with customers, vendors and others, we have entered into off–balance sheet arrangements, such as letters of credit and other bank issued guarantees, which totaled approximately $319.8 million at December 31, 2005. We also had commitments outstanding for purchase obligations related to capital expenditures and inventory under purchase orders and contracts of approximately $173.0 million at December 31, 2005. In addition, at December 31, 2005, we have guaranteed debt and other

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

obligations of third parties with a maximum exposure of $1.4 million. It is not practicable to estimate the fair value of these financial instruments. None of the off–balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.

NOTE 17. OTHER SUPPLEMENTAL INFORMATION

Supplemental consolidated statement of operations information is as follows for the years ended December 31:


	2005		2004		2003

Rental expense (generally transportation equipment and warehouse facilities)	$	138.7	$	123.5	$	111.5
Research and development		188.2		176.7		173.3

The changes in the aggregate product warranty liability are as follows:


Balance as of December 31, 2003	$	14.1
Claims paid		(4.9	)
Additional warranties		7.6
Other		(0.2	)

Balance as of December 31, 2004		16.6
Claims paid		(2.6	)
Additional warranties		2.1
Revisions in estimates for previously issued warranties		(2.5	)
Other		(0.2	)

Balance as of December 31, 2005	$	13.4

On December 31, 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47 (“FIN 47”),Conditional Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations,refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with the special handling of asbestos related materials in certain facilities. We also have certain facilities that contain asbestos related materials for which a liability has not been recognized because the fair value cannot be reasonably estimated. We believe that there are indeterminate settlement dates for these obligations because the range of time over which we would settle these obligations is unknown or cannot be estimated; therefore, sufficient information does not exist to apply an expected present value technique.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The changes in the asset retirement obligation liability are as follows:


Balance as of December 31, 2003	$	11.5
Liabilities incurred		1.5
Liabilities settled		(0.4	)
Accretion expense		0.2
Revisions to existing liabilities		(0.1	)
Translation adjustments		0.2

Balance as of December 31, 2004		12.9
Liabilities incurred		1.6
Liabilities settled		(0.2	)
Accretion expense		0.5
Revisions to existing liabilities		1.2
Adoption of FIN 47		1.6
Translation adjustments		(0.2	)

Balance as of December 31, 2005	$	17.4

Accumulated other comprehensive loss, net of tax, is comprised of the following at December 31:


	2005			2004

Foreign currency translation adjustments	$	(117.4	)	$	(52.4	)
Pension adjustment		(69.5	)		(57.3	)
Other		(1.1	)		(0.1	)

Total	$	(188.0	)	$	(109.8	)

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 18. QUARTERLY DATA (UNAUDITED)


	First		Second		Third		Fourth		Total
	Quarter		Quarter		Quarter		Quarter		Year

2005
Revenues	$	1,642.9	$	1,768.4	$	1,784.8	$	1,989.4	$	7,185.5
Gross profit⁽¹⁾		487.3		552.6		564.8		638.3		2,243.0
Income from continuing operations		178.4		218.0		220.6		257.4		874.4
Net income		179.8		218.8		221.9		257.9		878.4
Basic earnings per share:
Income from continuing operations		0.53		0.65		0.64		0.76		2.58
Net income		0.53		0.65		0.65		0.76		2.59
Diluted earnings per share:
Income from continuing operations		0.53		0.64		0.64		0.75		2.56
Net income		0.53		0.64		0.65		0.75		2.57
Dividends per share		0.115		0.115		0.115		0.130		0.475
Common stock market prices:
High		47.70		51.95		60.79		62.76
Low		41.20		42.51		51.54		51.20

2004
Revenues	$	1,381.5	$	1,493.7	$	1,532.0	$	1,672.4	$	6,079.6
Gross profit⁽¹⁾		370.3		426.3		432.5		499.5		1,728.6
Income from continuing operations		93.6		116.2		136.7		178.8		525.3
Net income		94.6		116.9		137.5		179.6		528.6
Basic earnings per share
Income from continuing operations		0.28		0.35		0.40		0.54		1.57
Net income		0.28		0.35		0.41		0.54		1.58
Diluted earnings per share
Income from continuing operations		0.28		0.35		0.40		0.53		1.57
Net income		0.28		0.35		0.41		0.53		1.58
Dividends per share		0.11		0.12		0.11		0.12		0.46
Common stock market prices:
High		38.42		38.27		44.57		44.89
Low		32.00		33.71		37.80		40.28


⁽¹⁾		Represents revenues less cost of revenues.

NOTE 19. SUBSEQUENT EVENTS (UNAUDITED)

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of December 31, 2005, our management, including our principal executive officer and principal financial officer, conducted an evaluation of our disclosure controls and procedures. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures as of December 31, 2005 are effective in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Design and Evaluation of Internal Control Over Financial Reporting

Pursuant to Section 404 of the Sarbanes—Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls as part of this Annual Report on Form 10—K for the fiscal year ended December 31, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the captions entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information concerning our directors is set forth in the sections entitled “Proposal No. 1, Election of Directors,” and “Corporate Governance — Committees of the Board — Audit/Ethics Committee” in our Proxy Statement for the Annual Meeting of Stockholders to be held April 27, 2006 (“Proxy Statement”), which sections are incorporated herein by reference. For information regarding our executive officers, see “Item 1. Business — Executive Officers” in this annual report on Form 10—K. Additional information regarding compliance by directors and executive officers with Section 16(a) of the Exchange Act is set forth under the section entitled “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which section is incorporated herein by reference. For information concerning our code of ethics, see “Item 1. Business” in this annual report on Form 10—K.

ITEM 11. EXECUTIVE COMPENSATION

Information for this item is set forth in the sections entitled “Executive Compensation — Summary Compensation Table,” “Corporate Governance — Board of Directors,” “Stock Options Granted During 2005,” “Aggregated Option Exercises During 2005 and Option Values at December 31, 2005,” “Long—Term Incentive Plan Awards During 2005,” “Pension Plan Table,” “ Employment, Change in Control, and Indemnification Agreements,” “Compensation Committee Report,” “Compensation Committee Interlocks and Insider Participation,” and “Corporate Performance Graph” in our Proxy Statement, which sections are incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information concerning security ownership of certain beneficial owners and our management is set forth in the sections entitled “Voting Securities” and “Security Ownership of Management” in our Proxy Statement, which sections are incorporated herein by reference.

Our Board of Directors has approved procedures for use under our Securities Trading and Disclosure Policy to permit our employees, officers and directors to enter into written trading plans complying with Rule 10b5—1 under the Exchange Act. Rule 10b5—1 provides criteria under which such an individual may establish a prearranged plan to buy or sell a specified number of shares of a company’s stock over a set period of time. Any such plan must be entered into in good faith at a time when the individual is not in possession of material, nonpublic information. If an individual establishes a plan satisfying the requirements of Rule 10b5—1, such individual’s subsequent receipt of material, nonpublic information will not prevent transactions under the plan from being executed. Certain of our officers have advised us that they have and may enter into a stock sales plan for the sale of shares of our common stock which are intended to comply with the requirements of Rule 10b5—1 promulgated by the Securities Exchange Act of 1934.

Equity Compensation Plan Information

The information in the following table is presented as of December 31, 2005 with respect to shares of our common stock that may be issued under our existing equity compensation plans, including the Baker Hughes Incorporated 1993 Stock Option Plan, the Baker Hughes Incorporated Long—Term Incentive Plan and the Baker Hughes Incorporated 2002 Directors & Officers Long—Term Incentive Plan, all of which have been approved by our stockholders.

(In millions of shares)

Number of Securities

Remaining Available for

Number of Securities

Weighted—Average

Future Issuance Under

to be Issued Upon

Exercise Price of

Equity Compensation

Exercise of

Outstanding

Plans (excluding

Outstanding Options,

Options, Warrants

securities reflected in the

Equity Compensation Plan Category

Warrants and Rights

and Rights

first column)

Stockholder—approved plans (excluding Employee Stock Purchase Plan)

1.7

⁽²⁾

39.23

4.1

Nonstockholder—approved plans⁽¹⁾

3.8

38.79

7.2

Subtotal (except for weighted average exercise price)

5.5

38.92

11.3

Employee Stock Purchase Plan

—

⁽³⁾

3.4

Total

5.5

⁽⁴⁾

14.7


⁽¹⁾		The table includes the nonstockholder—approved plans: the 1998 Employee Stock Option Plan, the 1998 Special Employee Stock Option Plan, the 2002 Employee Long—Term Incentive Plan and the Director Compensation Deferral Plan. A description of each of these plans is set forth below.

⁽²⁾		The table includes approximately 0.9 million shares of our common stock that would be issuable upon the exercise of the outstanding options under our 1993 Stock Option Plan, which expired in 2003. No additional options may be granted under the 1993 Stock Option Plan.

⁽³⁾		In the Baker Hughes Incorporated Employee Stock Purchase Plan, the purchase price is determined in accordance with Section 423 of the Code, as amended, as 85% of the lower of the fair market value on the date of grant or the date of purchase.

⁽⁴⁾		The table does not include shares subject to outstanding options we assumed in connection with certain mergers and acquisitions of entities which originally granted those options. When we acquired the stock of Western Atlas Inc. in a transaction completed in August 1998, we assumed the options granted under the Western Atlas Director Stock Option Plan and the Western Atlas 1993 Stock Incentive Plan. As of December 31, 2005, 36,159 shares and 3,836 shares of our common stock would be issuable upon the exercise of outstanding options previously granted under the Western Atlas Director Stock Option Plan and the Western Atlas 1993 Stock Incentive Plan, with a weighted average exercise price per share of $25.56 and $26.07, respectively.

Our nonstockholder—approved plans are described below:

1998 Employee Stock Option Plan

The Baker Hughes Incorporated 1998 Employee Stock Option Plan (the “1998 ESOP”) was adopted effective as of October 1, 1998. The number of shares authorized for issuance under the 1998 ESOP is 3.5 million shares. Nonqualified stock options may be granted under the 1998 ESOP to our employees. The exercise price of the options will be equal to the fair market value per share of our common stock on the date of grant, and option terms may be up to ten years. Under the terms and conditions of the option award agreements for options issued under the 1998 ESOP, options generally vest and become exercisable in installments over the optionee’s period of service, and the options vest on an accelerated basis in the event of a change in control. As of December 31, 2005, options covering approximately 0.5 million shares of our common stock were outstanding under the 1998 ESOP, options covering approximately 0.9 million shares were exercised during fiscal year 2005 and approximately 0.3 million shares remained available for future options.

1998 Special Employee Stock Option Plan

The Baker Hughes Incorporated 1998 Special Employee Stock Option Plan (the “1998 SESOP”) was adopted effective as of October 22, 1997. The number of shares authorized for issuance upon the exercise of options granted under the 1998 SESOP is 2.5 million shares. Under the 1998 SESOP, the Compensation Committee of our Board of Directors has the authority to grant nonqualified stock options to purchase shares of our common stock to a broad–based group of employees. The exercise price of the options will be equal to the fair market value per share of our common stock at the time of the grant, and option terms may be up to ten years. Stock option grants of 100 shares, with an exercise price of $47.813 per share, were issued to all of our U.S. employees in October 1997 and to our international employees in May 1998. As of December 31, 2005, options covering approximately 0.5 million shares of our common stock were outstanding under the 1998 SESOP, options covering approximately 0.4 million shares were exercised during fiscal year 2005 and approximately 1.7 million shares remained available for future options.

2002 Employee Long–Term Incentive Plan

The Baker Hughes Incorporated 2002 Employee Long–Term Incentive Plan (the “2002 Employee LTIP”) was adopted effective as of March 6, 2002. The 2002 Employee LTIP permits the grant of awards as nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, stock awards and cash–based awards to our corporate officers and key employees. The number of shares authorized for issuance under the 2002 Employee LTIP is 9.5 million, with no more than 3.0 million available for grant as awards other than options (the number of shares is subject to adjustment for changes in our common stock).

The 2002 Employee LTIP is the companion plan to the Baker Hughes Incorporated 2002 Director & Officer Long–Term Incentive Plan, which was approved by our stockholders in 2002. The rationale for the two companion plans was to discontinue the use of the remaining older option plans and to have only two plans from which we would issue compensation awards.

Options.The exercise price of the options will not be less than the fair market value of the shares of our common stock on the date of grant, and options terms may be up to ten years. The maximum number of shares of our common stock that may be subject to options granted under the 2002 Employee LTIP to any one employee during any one fiscal year will not exceed 3.0 million, subject to adjustment under the antidilution provisions of the 2002 Employee LTIP. Under the terms and conditions of the stock option awards for options issued under the 2002 Employee LTIP, options generally vest and become exercisable in installments over the optionee’s period of service, and the options vest on an accelerated basis in the event of a change in control or certain terminations of employment. As of December 31, 2005, options covering approximately 2.8 million shares of our common stock were outstanding under the 2002 Employee LTIP, options covering approximately 1.0 million shares were exercised during fiscal year 2005 and approximately 4.8 million shares remained available for future options.

Performance Shares and Units; Cash–Based Awards.Performance shares may be granted to employees in the amounts and upon the terms determined by the Compensation Committee of our Board of Directors, but must be limited to no more than 1.0 million shares to any one employee in any one fiscal year. Performance shares will have an initial value equal to the fair market value of our common stock at the date of the award. Performance units and cash–based awards may be granted to employees in amounts and upon the terms determined by the Compensation Committee, but must be limited to no more than $10.0 million for any one employee in any one fiscal year. The performance measures that may be used to determine the extent of the actual performance payout or vesting include, but are not limited to, net earnings; earnings per share; return measures; cash flow return on investments (net cash

flows divided by owner’s equity); earnings before or after taxes, interest, depreciation and/or amortization; share price (including growth measures and total shareholder return) and Baker Value Added (our metric that measures operating profit after tax less the cost of capital employed).

Restricted Stock and Restricted Stock Units.With respect to awards of restricted stock and restricted stock units, the Compensation Committee will determine the conditions or restrictions on the awards, including whether the holders of the restricted stock or restricted stock units will exercise full voting rights or receive dividends and other distributions during the restriction period. At the time the award is made, the Compensation Committee will determine the right to receive unvested restricted stock or restricted units after termination of service. Awards of restricted stock are limited to 1.0 million shares in any one year to any one individual.

Stock Appreciation Rights.Stock appreciation rights may be granted under the 2002 Employee LTIP on the terms and conditions determined by the Compensation Committee. The grant price of a freestanding stock appreciation right will not be less than the fair market value of our common stock on the date of grant. The maximum number of shares of our common stock that may be utilized for purposes of determining an employee’s compensation under stock appreciation rights granted under the 2002 Employee LTIP during any one fiscal year will not exceed 3.0 million shares, subject to adjustment under the antidilution provisions of the 2002 Employee LTIP.

Administration; Amendment and Termination. The Compensation Committee shall administer the 2002 Employee LTIP, and in the absence of the Compensation Committee, the Board will administer the Plan. The Compensation Committee will have full and exclusive power to interpret the provisions of the 2002 Employee LTIP as the Committee may deem necessary or proper, with the powers exercised in the best interests of the Company and in keeping with the objectives of the Plan. The Board may alter, amend, modify, suspend or terminate the 2002 Employee LTIP, except that no amendment, modification, suspension or termination that would adversely affect in any material way the rights of a participant under any award previously granted under the Plan may be made without the written consent of the participant or to the extent stockholder approval is otherwise required by applicable legal requirements.

Director Compensation Deferral Plan

The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective July 24, 2002 (the “Deferral Plan”), is intended to provide a means for members of our Board of Directors to defer compensation otherwise payable and provide flexibility with respect to our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer income with respect to each calendar year. The compensation deferrals may be stock option–related deferrals or cash–based deferrals. The stock option–related deferrals may be either market–priced stock options or discounted stock options. The number of shares to be issued for the market–priced stock option deferral is calculated on a quarterly basis by multiplying the deferred compensation by 4.4 and then dividing by the fair market value of our common stock on the last day of the quarter. The number of shares to be issued for the discounted stock option deferral is calculated on a quarterly basis by dividing the deferred compensation by the discounted price of our common stock on the last day of the quarter. The discounted price is 50% of the fair market value of our common stock on the valuation date. Stock options granted under the Deferral Plan vest on the first anniversary of the date of grant and must be exercised within 10 years of the date of grant. If a director’s directorship terminates for any reason, any options outstanding will expire 3 years after the termination of the directorship. The maximum aggregate number of shares of our common stock that may be issued under the Deferral Plan is 0.5 million. As of December 31, 2005, options covering 4,191 shares of our common stock were outstanding under the Deferral Plan, options covering 2,880 shares were exercised during fiscal 2005 and approximately 0.5 million shares remained available for future options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information regarding related party transactions is set forth in the sections entitled “Executive Compensation — Employment, Change in Control, and Indemnification Agreements” in our Proxy Statement, which sections are incorporated by reference herein.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning principal accounting fees and services is set forth in the section entitled “Fees Paid to Deloitte & Touche LLP” in our Proxy Statement, which section is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

List of Documents filed as part of this Report

	(1)		Financial Statements

			All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10–K.

	(2)		Financial Statement Schedules

			Schedule II — Valuation and Qualifying Accounts

	(3)		Exhibits

			Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Annual Report on Form 10–K. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.

	3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended June 30, 2002).

	3.2		Certificate of Amendment to the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8–K filed May 4, 2005).

	3.3		Bylaws of Baker Hughes Incorporated restated as of April 28, 2005 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8–K filed May 4, 2005).

	4.1		Rights of Holders of the Company’s Long–Term Debt. The Company has no long–term debt instrument with regard to which the securities authorized thereunder equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long–term debt instruments to the SEC upon request.

	4.2		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended June 30, 2002).

	4.3		Certificate of Amendment to the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8–K filed May 4, 2005).

	4.4		Bylaws of Baker Hughes Incorporated restated as of April 28, 2005 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8–K filed May 4, 2005).

	4.5		Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004).

	10.1+		Employment Agreement by and between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8–K filed October 7, 2004).

	10.2+		Change in Control Agreement between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8–K filed October 7, 2004).

	10.3+		Indemnification Agreement dated as of October 25, 2004 between Baker Hughes Incorporated and Chad C. Deaton (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8–K filed on October 7, 2004).

	10.4+		Stock Option Agreement issued to Chad C. Deaton on October 25, 2004 in the amount of 75,000 shares of Company Common Stock (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2004).

	10.5+		Agreement regarding restricted stock award issued to Chad C. Deaton on October 25, 2004 in the amount of 80,000 shares of Company Common Stock (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2004).

	10.6+		Agreement regarding restricted stock award issued to James R. Clark on October 27, 2004 in the amount of 40,000 shares of Baker Hughes Incorporated Common Stock (filed as Exhibit 10.7 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2004).

	10.7+		Second Amended and Restated Stock Matching Agreement by and between Baker Hughes Incorporated and James R. Clark dated as of October 25, 2004 (filed as Exhibit 10.6 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2004).

	10.8+		Letter dated October 26, 2005 to James R. Clark clarifying Mr. Clark’s employment terms (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2005).

	10.9+*		Retirement and Consulting Agreement dated November 1, 2005 and clarification letter dated February 15, 2006 between Baker Hughes Incorporated and G. Stephen Finley effective as of April 1, 2006.

	10.10+		Form of Change in Control Severance Plan (filed as Exhibit 10.8 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.11+		Form of Change in Control Severance Agreement between Baker Hughes Incorporated and David H. Barr and John A. O’Donnell effective as of July 28, 2004, and with James R. Clark, Alan R. Crain, Jr., William P. Faubel, G. Stephen Finley, Greg Nakanishi and Douglas J. Wall to be effective as of January 1, 2006 and with Chris P. Beaver, Paul S. Butero and Martin S. Craighead effective as of February 28, 2005 and with Richard L. Williams effective as of May 2, 2005 and with Charles S. Wolley effective as of January 1, 2006 (filed as Exhibit 10.8 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2004).

	10.12+		Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.13+		Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.14+		Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of July 24, 2002 (filed as Exhibit 10.16 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.15+		Baker Hughes Incorporated Executive Severance Plan (effective November 1, 2002) (filed as Exhibit 10.13 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.16		1995 Employee Annual Incentive Compensation Plan, as amended by Amendment No. 1997–1 to the 1995 Employee Annual Incentive Compensation Plan and as amended by Amendment No. 1999–1 to the 1995 Employee Annual Incentive Compensation Plan (filed as Exhibit 10.17 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.17+		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2005).

	10.18		Long–Term Incentive Plan, as amended by Amendment No. 1999–1 to Long–Term Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.19		Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by Amendment No. 1999–1 to 1998 Employee Stock Option Plan (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended June 30, 2003).

	10.20		Baker Hughes Incorporated 2002 Employee Long–Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333–87372 on Form S–8 filed May 1, 2002).

	10.21+		Baker Hughes Incorporated 2002 Director & Officer Long–Term Incentive Plan (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended September 30, 2003).

	10.22+		Amendment to 2002 Director & Officer Long–Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005).

	10.23		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of March 3, 2003 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended March 31, 2003).

	10.24		Baker Hughes Incorporated Pension Plan effective as of January 1, 2002, as amended by First Amendment, effective January 1, 2002 (filed as Exhibit 10.51 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.25		Form of Nonqualified Stock Option Agreement for employees effective October 25, 1995 (filed as Exhibit 10.27 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.26		Form of Incentive Stock Option Agreement for employees effective October 25, 1995 (filed as Exhibit 10.28 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.27+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1995 (filed as Exhibit 10.26 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.28+		Form of Stock Option Agreement for executive officers effective October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2000).

	10.29+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2000).

	10.30+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.31		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.32		Form of Baker Hughes Incorporated Incentive Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2001).

	10.33+		Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2002).

	10.34+		Form of Baker Hughes Incorporated Performance Award Agreement, including Terms and Conditions for certain executive officers (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended March 31, 2004).

	10.35+		Form of Restricted Stock Award Resolution, including Terms and Conditions (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10–Q for the quarter ended March 31, 2004).

	10.36+		Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed as Exhibit 10.54 to Annual Report on Form 10–K for the year ended December 31, 2004).

	10.37+		Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed as Exhibit 10.54 to Annual Report on Form 10–K for the year ended December 31, 2004).

	10.38		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 to Annual Report on Form 10–K for the year ended December 31, 2004).

	10.39		Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 to Annual Report on Form 10–K for the year ended December 31, 2004).

	10.40+*		Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors.

	10.41+*		Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors.

	10.42+*		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions.

	10.43+*		Performance Goals for the Performance Unit Award granted in 2006.

	10.44+*		Compensation Table for Named Executive Officers and Directors.

	10.45		Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent and fourteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8–K filed July 11, 2005).

	10.46		Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.47		Tax Sharing Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.31 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.48		Employee Benefits Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker Hughes Incorporated on Form 10–K for the year ended December 31, 2003).

	10.49		Master Formation Agreement by and among the Company, Schlumberger Limited and certain wholly owned subsidiaries of Schlumberger Limited dated as of September 6, 2000 (filed as Exhibit 2.1 to Current Report of Baker Hughes Incorporated on Form 8–K dated September 7, 2000).

	10.50		Shareholders’ Agreement by and among Schlumberger Limited, Baker Hughes Incorporated and other parties listed on the signature pages thereto dated November 30, 2000 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8–K dated November 30, 2000).

	21.1*		Subsidiaries of Registrant.

	23.1*		Consent of Deloitte & Touche LLP.

	31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated February 28, 2006, pursuant to Rule 13a–14(a) of the Securities Exchange Act of 1934, as amended.

	31.2*		Certification of G. Stephen Finley, Chief Financial Officer, dated February 28, 2006, pursuant to Rule 13a–14(a) of the Securities Exchange Act of 1934, as amended.

	32*		Statement of Chad C. Deaton, Chief Executive Officer, and G. Stephen Finley, Chief Financial Officer, dated February 28, 2006, furnished pursuant to Rule 13a–14(b) of the Securities Exchange Act of 1934, as amended.

	99.1		Administrative Proceeding, File No. 3–10572, dated September 12, 2001, as issued by the Securities and Exchange Commission (filed as Exhibit 99.1 to Current Report on Form 8–K filed on September 19, 2001).

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BAKER HUGHES INCORPORATED
Date: February 28, 2006	/s/CHAD C. DEATON
	Chad C. Deaton
	Chairman of the Board and Chief Executive Officer

KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Chad. C. Deaton and G. Stephen Finley, each of whom may act without joinder of the other, as their true and lawful attorneys–in–fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10–K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys–in–fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys–in–fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/CHAD C. DEATON	Chairman of the Board and Chief Executive	February 28, 2006
(Chad C. Deaton)	Officer (principal executive officer)

/s/G. STEPHEN FINLEY	Senior Vice President — Finance and	February 28, 2006
(G. Stephen Finley)	Administration and Chief Financial Officer (principal financial officer)

/s/ALAN J. KEIFER	Vice President and Controller	February 28, 2006
(Alan J. Keifer)	(principal accounting officer)

/s/LARRY D. BRADY	Director	February 28, 2006
(Larry D. Brady)

/s/CLARENCE P. CAZALOT, JR.	Director	February 28, 2006
(Clarence P. Cazalot, Jr.)

	Director
(Edward P. Djerejian)

/s/ANTHONY G. FERNANDES	Director	February 28, 2006
(Anthony G. Fernandes)

/s/CLAIRE W. GARGALLI	Director	February 28, 2006
(Claire W. Gargalli)

/s/JAMES A. LASH	Director	February 28, 2006
(James A. Lash)

/s/JAMES F. MCCALL	Director	February 28, 2006
(James F. McCall)

/s/J. LARRY NICHOLS	Director	February 28, 2006
(J. Larry Nichols)

/s/H. JOHN RILEY, JR.	Director	February 28, 2006
(H. John Riley, Jr.)

/s/CHARLES L. WATSON	Director	February 28, 2006
(Charles L. Watson)

Baker Hughes Incorporated

Schedule II — Valuation and Qualifying Accounts


					Deductions
			Additions
	Balance at		Charged to		Reversal of						Charged to			Balance at
	Beginning		Cost and		Prior						Other			End of
(In millions)	of Period		Expenses		Deductions⁽¹⁾			Write–offs⁽²⁾			Accounts⁽³⁾			Period


Year ended December 31, 2005:
Reserve for doubtful accounts receivable	$	50.2	$	28.3	$	(14.8	)	$	(8.0	)	$	(4.3	)	$	51.4
Reserve for inventories		220.0		31.4		—			(42.1	)		(8.0	)		201.3

Year ended December 31, 2004:
Reserve for doubtful accounts receivable		61.6		21.1		(19.3	)		(14.4	)		1.2			50.2
Reserve for inventories		231.5		38.8		—			(59.3	)		9.0			220.0

Year ended December 31, 2003:
Reserve for doubtful accounts receivable		66.2		18.1		(9.7	)		(13.5	)		0.5			61.6
Reserve for inventories		233.6		23.0		—			(36.1	)		11.0			231.5


⁽¹⁾		Represents the reversals of prior accruals as receivables are collected.

⁽²⁾		Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless.

⁽³⁾		Represents reclasses, currency translation adjustments and divestitures.

INDEX OF EXHIBITS

3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2002).

3.2		Certificate of Amendment to the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4, 2005).

3.3		Bylaws of Baker Hughes Incorporated restated as of April 28, 2005 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4, 2005).

4.1		Rights of Holders of the Company’s Long-Term Debt. The Company has no long-term debt instrument with regard to which the securities authorized thereunder equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request.

4.2		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2002).

4.3		Certificate of Amendment to the Restated Certificate of Incorporation (filed as Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4, 2005).

4.4		Bylaws of Baker Hughes Incorporated restated as of April 28, 2005 (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4, 2005).

4.5		Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004).

10.1+		Employment Agreement by and between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

10.2+		Change in Control Agreement between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

10.3+		Indemnification Agreement dated as of October 25, 2004 between Baker Hughes Incorporated and Chad C. Deaton (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on October 7, 2004).

10.4+		Stock Option Agreement issued to Chad C. Deaton on October 25, 2004 in the amount of 75,000 shares of Company Common Stock (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.5+		Agreement regarding restricted stock award issued to Chad C. Deaton on October 25, 2004 in the amount of 80,000 shares of Company Common Stock (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.6+		Agreement regarding restricted stock award issued to James R. Clark on October 27, 2004 in the amount of 40,000 shares of Baker Hughes Incorporated Common Stock (filed as Exhibit 10.7 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.7+		Second Amended and Restated Stock Matching Agreement by and between Baker Hughes Incorporated and James R. Clark dated as of October 25, 2004 (filed as Exhibit 10.6 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.8+		Letter dated October 26, 2005 to James R. Clark clarifying Mr. Clark’s employment terms (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).

10.9+*		Retirement and Consulting Agreement dated November 1, 2005 and clarification letter dated February 15, 2006 between Baker Hughes Incorporated and G. Stephen Finley effective as of April 1, 2006.

10.10+		Form of Change in Control Severance Plan (filed as Exhibit 10.8 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.11+		Form of Change in Control Severance Agreement between Baker Hughes Incorporated and David H. Barr and John A. O’Donnell effective as of July 28, 2004, and with James R. Clark, Alan R. Crain, Jr., William P. Faubel, G. Stephen Finley, Greg Nakanishi and Douglas J. Wall to be effective as of January 1, 2006 and with Chris P. Beaver, Paul S. Butero and Martin S. Craighead effective as of February 28, 2005 and with Richard L. Williams effective as of May 2, 2005 and with Charles S. Wolley effective as of January 1, 2006 (filed as Exhibit 10.8 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.12+		Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.13+		Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.14+		Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of July 24, 2002 (filed as Exhibit 10.16 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.15+		Baker Hughes Incorporated Executive Severance Plan (effective November 1, 2002) (filed as Exhibit 10.13 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.16		1995 Employee Annual Incentive Compensation Plan, as amended by Amendment No. 1997-1 to the 1995 Employee Annual Incentive Compensation Plan and as amended by Amendment No. 1999-1 to the 1995 Employee Annual Incentive Compensation Plan (filed as Exhibit 10.17 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.17+		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).

10.18		Long-Term Incentive Plan, as amended by Amendment No. 1999-1 to Long-Term Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.19		Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by Amendment No. 1999-1 to 1998 Employee Stock Option Plan (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2003).

10.20		Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333-87372 on Form S-8 filed May 1, 2002).

10.21+		Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2003).

10.22+		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005).

10.23		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of March 3, 2003 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2003).

10.24		Baker Hughes Incorporated Pension Plan effective as of January 1, 2002, as amended by First Amendment, effective January 1, 2002 (filed as Exhibit 10.51 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.25		Form of Nonqualified Stock Option Agreement for employees effective October 25, 1995 (filed as Exhibit 10.27 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.26		Form of Incentive Stock Option Agreement for employees effective October 25, 1995 (filed as Exhibit 10.28 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.27+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1995 (filed as Exhibit 10.26 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.28+		Form of Stock Option Agreement for executive officers effective October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.29+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.30+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.31		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.32		Form of Baker Hughes Incorporated Incentive Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.33+		Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.34+		Form of Baker Hughes Incorporated Performance Award Agreement, including Terms and Conditions for certain executive officers (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

10.35+		Form of Restricted Stock Award Resolution, including Terms and Conditions (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

10.36+		Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.37+		Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.38		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.39		Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.40+*		Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors.

10.41+*		Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors.

10.42+*		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions.

10.43+*		Performance Goals for the Performance Unit Award granted in 2006.

10.44+*		Compensation Table for Named Executive Officers and Directors.

10.45		Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent and fourteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed July 11, 2005).

10.46		Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.47		Tax Sharing Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.31 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.48		Employee Benefits Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.49		Master Formation Agreement by and among the Company, Schlumberger Limited and certain wholly owned subsidiaries of Schlumberger Limited dated as of September 6, 2000 (filed as Exhibit 2.1 to Current Report of Baker Hughes Incorporated on Form 8-K dated September 7, 2000).

10.50		Shareholders’ Agreement by and among Schlumberger Limited, Baker Hughes Incorporated and other parties listed on the signature pages thereto dated November 30, 2000 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K dated November 30, 2000).

21.1*		Subsidiaries of Registrant.

23.1*		Consent of Deloitte & Touche LLP.

31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated February 28, 2006, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of G. Stephen Finley, Chief Financial Officer, dated February 28, 2006, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

32*		Statement of Chad C. Deaton, Chief Executive Officer, and G. Stephen Finley, Chief Financial Officer, dated February 28, 2006, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

99.1		Administrative Proceeding, File No. 3-10572, dated September 12, 2001, as issued by the Securities and Exchange Commission (filed as Exhibit 99.1 to Current Report on Form 8-K filed on September 19, 2001).

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BAKER HUGHES a GE (BHI) 10-K2005 FY Annual report

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